e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended:
December 31, 2008
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number:
001-32678
DCP MIDSTREAM PARTNERS,
LP
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other
jurisdiction
of incorporation or organization)
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03-0567133
(I.R.S. Employer
Identification No.)
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370 17th Street, Suite 2775
Denver, Colorado
(Address of principal
executive offices)
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80202
(Zip Code)
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Registrants telephone number, including area code:
303-633-2900
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class:
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Name of Each Exchange on Which Registered:
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
NONE
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Exchange Act of 1934, or the
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Act during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for
the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of common limited partner units held
by non-affiliates of the registrant on June 30, 2008, was
approximately $582,555,000. The aggregate market value was
computed by reference to the last sale price of the
registrants common units on the New York Stock Exchange on
June 30, 2008.
As of February 23, 2009, there were outstanding 28,233,183
common limited partner units.
DOCUMENTS
INCORPORATED BY REFERENCE:
None.
DCP
MIDSTREAM PARTNERS, LP
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2008
TABLE OF
CONTENTS
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GLOSSARY
OF TERMS
The following is a list of certain industry terms used
throughout this report:
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Bbl
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barrel
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Bbls/d
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barrels per day
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BBtu/d
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one billion Btus per day
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Bcf/d
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one billion cubic feet per day
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Btu
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British thermal unit, a measurement of energy
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Fractionation
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the process by which natural gas liquids are separated into
individual components
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Frac spread
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price differences, measured in energy units, between equivalent
amounts of natural gas and NGLs
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MBbls
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one thousand barrels
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MBbls/d
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one thousand barrels per day
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MMBtu
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one million Btus
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MMBtu/d
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one million Btus per day
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MMcf
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one million cubic feet
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MMcf/d
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one million cubic feet per day
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MMscf
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one million standard cubic feet
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NGLs
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natural gas liquids
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Tcf
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one trillion cubic feet
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Throughput
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the volume of product transported or passing through a pipeline
or other facility
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ii
CAUTIONARY
STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from
time to time contain statements that do not directly or
exclusively relate to historical facts. Such statements are
forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. You can
typically identify forward-looking statements by the use of
forward-looking words, such as may,
could, project, believe,
anticipate, expect,
estimate, potential, plan,
forecast and other similar words.
All statements that are not statements of historical facts,
including statements regarding our future financial position,
business strategy, budgets, projected costs and plans and
objectives of management for future operations, are
forward-looking statements.
These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and
are subject to risks, uncertainties and other factors, many of
which are outside our control. Important factors that could
cause actual results to differ materially from the expectations
expressed or implied in the forward-looking statements include
known and unknown risks. Known risks and uncertainties include,
but are not limited to, the risks set forth in
Item 1A. Risk Factors as well as the following
risks and uncertainties:
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the extent of changes in commodity prices, our ability to
effectively limit a portion of the adverse impact of potential
changes in prices through derivative financial instruments, and
the potential impact of price on natural gas drilling, demand
for our services, and the volume of NGLs and condensate
extracted;
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general economic, market and business conditions;
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the level and success of natural gas drilling around our assets,
and our ability to connect supplies to our gathering and
processing systems in light of competition;
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our ability to grow through acquisitions, contributions from
affiliates, or organic growth projects, and the successful
integration and future performance of such assets;
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our ability to access the debt and equity markets, which will
depend on general market conditions, interest rates and our
ability to effectively limit a portion of the adverse effects of
potential changes in interest rates by entering into derivative
financial instruments, and the credit ratings for our debt
obligations;
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our ability to purchase propane from our principal suppliers for
our wholesale propane logistics business;
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our ability to construct facilities in a timely fashion, which
is partially dependent on obtaining required building,
environmental and other permits issued by federal, state and
municipal governments, or agencies thereof, the availability of
specialized contractors and laborers, and the price of and
demand for supplies;
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the creditworthiness of counterparties to our transactions;
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weather and other natural phenomena, including their potential
impact on demand for the commodities we sell and our
third-party-owned infrastructure;
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changes in laws and regulations, particularly with regard to
taxes, safety and protection of the environment or the increased
regulation of our industry;
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industry changes, including the impact of consolidations,
increased delivery of liquefied natural gas to the United
States, alternative energy sources, technological advances and
changes in competition; and
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the amount of collateral we may be required to post from time to
time in our transactions.
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In light of these risks, uncertainties and assumptions, the
events described in the forward-looking statements might not
occur or might occur to a different extent or at a different
time than we have described. We undertake no obligation to
publicly update or revise any forward-looking statements,
whether as a result of new information, future events or
otherwise.
1
Our
Partnership
DCP Midstream Partners, LP along with its consolidated
subsidiaries, or we, us, our, or the partnership, is a Delaware
limited partnership formed in August 2005 by DCP Midstream, LLC
to own, operate, acquire and develop a diversified portfolio of
complementary midstream energy assets. We completed our initial
public offering on December 7, 2005. We are currently
engaged in the business of gathering, compressing, treating,
processing, transporting and selling natural gas, producing,
transporting, storing and selling propane in wholesale markets
and transporting and selling NGLs and condensate. Supported by
our relationship with DCP Midstream, LLC and its parents,
Spectra Energy Corp, or Spectra Energy, and ConocoPhillips, we
have a management team dedicated to executing our growth
strategy by acquiring and constructing additional assets.
Our operations are organized into three business segments,
Natural Gas Services, Wholesale Propane Logistics and NGL
Logistics. A map representing the location of the assets that
comprise our segments is set forth below. Additional maps
detailing the individual assets can be found on our website at
www.dcppartners.com.
Our Natural Gas Services segment includes:
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Our Northern Louisiana system, which is an integrated pipeline
system located in northern Louisiana and southern Arkansas that
gathers, compresses, treats, processes, transports and sells
natural gas, and that transports and sells NGLs and condensate.
This system consists of the following:
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the Minden processing plant and gathering system, which includes
a
115 MMcf/d
cryogenic natural gas processing plant supplied by approximately
725 miles of natural gas gathering pipelines, connected to
approximately 460 receipt points, with throughput and processing
capacity of approximately
115 MMcf/d;
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the Ada processing plant and gathering system, which includes a
45 MMcf/d
refrigeration natural gas processing plant supplied by
approximately 130 miles of natural gas gathering pipelines,
connected to approximately 210 receipt points, with throughput
capacity of approximately
80 MMcf/d; and
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the Pelico Pipeline, LLC system, or Pelico system, an
approximately
600-mile
intrastate natural gas gathering and transportation pipeline
with throughput capacity of approximately
250 MMcf/d
and connections to the Minden and Ada processing plants and
approximately 450 other receipt points. The Pelico system
delivers natural gas to multiple interstate and intrastate
pipelines, as well as directly to industrial and utility end-use
markets.
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Our Southern Oklahoma, or Lindsay, gathering system, which was
acquired in May 2007, consists of approximately 225 miles
of pipeline, with throughput capacity of approximately
35 MMcf/d.
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Our equity interests that were acquired in July 2007 from DCP
Midstream, LLC, consist of the following:
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our 40% interest in Discovery Producer Services LLC, or
Discovery, which operates a
600 MMcf/d
cryogenic natural gas processing plant, a natural gas liquids
fractionator plant, an approximately
280-mile
natural gas pipeline with approximate throughput capacity of
600 MMcf/d
that transports gas from the Gulf of Mexico to its processing
plant, and several onshore laterals expanding its presence in
the Gulf; and
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our 25% interest in DCP East Texas Holdings, LLC, or East Texas,
which operates a
780 MMcf/d
natural gas processing complex, a natural gas liquids
fractionator and an approximately
900-mile
gathering system with approximate throughput capacity of
780 MMcf/d,
as well as third party gathering systems, and delivers residue
gas to interstate and intrastate pipelines.
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Our Colorado and Wyoming gathering, processing and compression
assets were acquired in August 2007 from DCP Midstream, LLC, and
consist of the following:
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our 70% operating interest in the approximately
30-mile
Collbran Valley Gas Gathering system, or Collbran system, has
assets in the Piceance Basin that gather and process natural gas
from over 20,000 dedicated acres in western Colorado, and a
processing facility with a capacity of
120 MMcf/d; and
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The Powder River Basin assets, which include the approximately
1,320-mile Douglas gas gathering system, or Douglas system, with
throughput capacity of approximately
60 MMcf/d
and covers more than 4,000 square miles in northeastern
Wyoming, and Millis terminal, and associated NGL pipelines in
southwestern Wyoming.
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Our Michigan gathering and treating assets were acquired in
October 2008 from Michigan Pipeline & Processing, LLC,
or MPP. These assets consist of five natural gas treating plants
and an approximately
155-mile gas
gathering pipeline system with throughput capacity of
330 MMcf/d;
an approximately
55-mile
residue gas pipeline; a 75% interest in Jackson Pipeline
Company, a partnership owning an approximately
25-mile
residue pipeline, or Jackson Pipeline; and a 44% interest in the
Litchfield pipeline, a
30-mile
pipeline whereby we lease our undivided interest to ANR Pipeline
Company through the use of a direct financing lease expiring in
2031.
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Our Wholesale Propane Logistics segment acquired in November
2006 from DCP Midstream, LLC includes:
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six owned rail terminals located in the Midwest and northeastern
United States, one of which was idled in 2007 to consolidate our
operations, with aggregate storage capacity of 25 MBbls;
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one leased marine terminal located in Providence, Rhode Island,
with storage capacity of 410 MBbls;
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one pipeline terminal located in Midland, Pennsylvania with
storage capacity of 56 MBbls; and
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access to several open access pipeline terminals.
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Our NGL Logistics segment includes:
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our Seabreeze pipeline, an approximately
68-mile
intrastate NGL pipeline located in Texas with throughput
capacity of 33 MBbls/d;
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our Wilbreeze pipeline, the construction of which was completed
in December 2006, an approximately
39-mile
intrastate NGL pipeline located in Texas, which connects a DCP
Midstream, LLC gas processing plant to the Seabreeze pipeline,
with throughput capacity of 11 MBbls/d; and
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our 45% interest in the Black Lake Pipe Line Company, or Black
Lake, the owner of an approximately
317-mile
interstate NGL pipeline in Louisiana and Texas with throughput
capacity of 40 MBbls/d.
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We have no revenue or segment profit or loss attributable to
international activities.
For additional information on our segments, please see
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations, and
Note 18 of the Notes to Consolidated Financial Statements
in Item 8. Financial Statements and Supplementary
Data.
Our
Business Strategies
Our primary business objective is to have sustained company
profitability and a strong balance sheet. In addition, we would
focus on profitable growth, thereby increasing our cash
distribution per unit over time. We intend to accomplish this
objective by executing the following business strategies:
Optimize: maximize the profitability of existing
assets. We intend to optimize the
profitability of our existing assets by maintaining existing
volumes and adding volumes to enhance utilization, improving
operating efficiencies and capturing marketing opportunities
when available. Our natural gas and NGL pipelines have excess
capacity, which allows us to connect new supplies of natural gas
and NGLs at minimal incremental cost. Our wholesale propane
logistics business has diversified supply options that allow us
to capture lower cost supply to lock in our margin, while
providing reliable supplies to our customers.
Build: capitalize on organic expansion
opportunities. We continually evaluate
economically attractive organic expansion opportunities to
construct new midstream systems in new or existing operating
areas. For example, we believe there are opportunities to expand
several of our gas gathering systems to attach increased volumes
of natural gas produced in the areas of our operations. We also
believe that we can continue to expand our wholesale propane
logistics business via the construction of new propane terminals.
Acquire: pursue strategic and accretive
acquisitions. We plan to pursue strategic and
accretive acquisition opportunities within the midstream energy
industry, both in new and existing lines of business, and
geographic areas of operation. We believe there will continue to
be acquisition opportunities as energy companies continue to
divest their midstream assets. We intend to pursue acquisition
opportunities both independently and jointly with DCP Midstream,
LLC and its parents, Spectra Energy and ConocoPhillips, and we
may also acquire assets directly from them, which we believe
will provide us with a broader array of growth opportunities
than those available to many of our competitors.
The execution of our business strategies and our level of growth
is dependent upon the availability and cost of capital, as well
as the availability of growth opportunities. The recent turmoil
in the capital markets has resulted in significantly higher
costs of public debt and equity funds.
Our
Competitive Strengths
We believe that we are well positioned to execute our business
strategies and achieve our primary business objective of
increasing our cash distribution per unit because of the
following competitive strengths:
Affiliation with DCP Midstream, LLC and its
parents. Our relationship with DCP Midstream,
LLC and its parents, Spectra Energy and ConocoPhillips, should
continue to provide us with significant business opportunities.
DCP Midstream, LLC is one of the largest gatherers of natural
gas (based on wellhead volume), one of the largest producers of
NGLs and one of the largest marketers of NGLs in North America.
This relationship also provides us with access to a significant
pool of management talent. We believe our strong relationships
throughout the energy industry, including with major producers
of natural gas and NGLs in the United States, will help
facilitate the implementation of our strategies. Additionally,
we believe DCP Midstream, LLC, which operates many of our assets
on our behalf, has established a reputation in the
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midstream business as a reliable and cost-effective supplier of
services to our customers, and has a track record of safe,
efficient and environmentally responsible operation of our
facilities.
Strategically located assets. Our
assets are strategically located in areas that hold potential
for expanding each of our business segments volume
throughput and cash flow generation. Our Natural Gas Services
segment has a strategic presence in several active natural gas
producing areas including western Colorado, northern Louisiana,
Michigan, southern Oklahoma, eastern Texas, northeastern Wyoming
and the Gulf of Mexico. These natural gas gathering systems
provide a variety of services to our customers including natural
gas gathering, compression, treating, processing, fractionation
and transportation services. The strategic location of our
assets, coupled with their geographic diversity, presents us
continuing opportunities to provide competitive natural gas
services to our customers and opportunities to attract new
natural gas production. Our NGL Logistics segment has
strategically located NGL transportation pipelines in northern
Louisiana, eastern Texas and southern Texas, all of which are
major NGL producing regions. Our NGL pipelines connect to
various natural gas processing plants in the region and
transport the NGLs to large fractionation facilities, a
petrochemical plant or an underground NGL storage facility along
the Gulf Coast. Our Wholesale Propane Logistics Segment has
terminals in the Northeastern and upper Midwestern states that
are strategically located to receive and deliver propane to one
of the largest demand areas for propane in the United States.
Stable cash flows. Our operations
consist of a favorable mix of fee-based and commodity-based
services, which together with our derivative activities,
generate relatively stable cash flows. While certain of our
gathering and processing contracts subject us to commodity price
risk, we have mitigated a significant portion of our currently
anticipated natural gas, NGL and condensate commodity price risk
associated with the equity volumes from our gathering and
processing operations through 2013 with fixed price natural gas
and crude oil swaps. For additional information regarding our
derivative activities, please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Quantitative and Qualitative Disclosures
about Market Risk Commodity Cash Flow Protection
Activities.
Integrated package of midstream
services. We provide an integrated package of
services to natural gas producers, including gathering,
compressing, treating, processing, transporting and selling
natural gas, as well as transporting and selling NGLs. We
believe our ability to provide all of these services gives us an
advantage in competing for new supplies of natural gas because
we can provide substantially all services that producers,
marketers and others require to move natural gas and NGLs from
wellhead to market on a cost-effective basis.
Comprehensive propane logistics
systems. We have multiple propane supply
sources and terminal locations for wholesale propane delivery.
We believe our diversity of supply sources and our ability to
purchase large volumes of propane supply and transport such
supply for resale or storage allows us to provide our customers
with reliable supplies of propane during periods of tight
supply. These capabilities also allow us to moderate the effects
of commodity price volatility and reduce significant
fluctuations in our sales volumes.
Experienced management team. Our senior
management team and board of directors includes some of the most
senior officers of DCP Midstream, LLC and former senior officers
from other energy companies who have extensive experience in the
midstream industry. Our management team has a proven track
record of enhancing value through the acquisition, optimization
and integration of midstream assets.
Our
Relationship with DCP Midstream, LLC and its Parents
One of our principal strengths is our relationship with DCP
Midstream, LLC and its parents, Spectra Energy and
ConocoPhillips. DCP Midstream, LLC intends to use us as an
important growth vehicle to pursue the acquisition, expansion,
and existing and organic construction of midstream natural gas,
NGL and other complementary energy businesses and assets. In
November 2006, we acquired our wholesale propane logistics
business, in July 2007, we acquired our interest in Discovery
and East Texas, and in August 2007, we acquired our Collbran and
Douglas systems associated with Momentum Energy Group, Inc., or
MEG, from DCP Midstream, LLC. We expect to have future
opportunities to make additional acquisitions directly from DCP
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Midstream, LLC; however, we cannot say with any certainty which,
if any, of these acquisitions may be made available to us, or if
we will choose to pursue any such opportunity. In addition,
through our relationship with DCP Midstream, LLC and its
parents, we expect to have access to a significant pool of
management talent, strong commercial relationships throughout
the energy industry and DCP Midstream, LLCs broad
operational, commercial, technical, risk management and
administrative infrastructure.
DCP Midstream, LLC has a significant interest in our partnership
through its approximately 1% general partner interest in us, all
of our incentive distribution rights and a 29% limited partner
interest in us. We have entered into an omnibus agreement, or
the Omnibus Agreement, with DCP Midstream, LLC and some of its
affiliates that governs our relationship with them regarding the
operation of many of our assets, as well as certain
reimbursement and indemnification matters.
Natural
Gas and NGLs Overview
The midstream natural gas industry is the link between
exploration and production of natural gas and the delivery of
its components to end-use markets, and consists of the
gathering, compression, treating, processing, transporting and
selling of natural gas, and the production, transporting and
selling of NGLs.
Midstream
Natural Gas Industry
Once natural gas is produced from wells, producers then seek to
deliver the natural gas and its components to end-use markets.
The following diagram illustrates the natural gas gathering,
processing, fractionation, storage and transportation process,
which ultimately results in natural gas and its components being
delivered to end-users.
Natural
Gas Gathering
The natural gas gathering process begins with the drilling of
wells into gas-bearing rock formations. Once the well is
completed, the well is connected to a gathering system. Onshore
gathering systems generally consist of a network of small
diameter pipelines that collect natural gas from points near
producing wells and transport it to larger pipelines for further
transmission.
Natural
Gas Compression
Gathering systems are generally operated at design pressures
that will maximize the total throughput from all connected
wells. Since wells produce at progressively lower field
pressures as they age, it becomes increasingly difficult to
deliver the remaining production from the ground against a
higher pressure that exists in the connecting gathering system.
Natural gas compression is a mechanical process in which a
volume of wellhead gas is compressed to a desired higher
pressure, allowing gas to flow into a higher pressure
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downstream pipeline to be brought to market. Field compression
is typically used to lower the pressure of a gathering system to
operate at a lower pressure or provide sufficient pressure to
deliver gas into a higher pressure downstream pipeline. If field
compression is not installed, then the remaining natural gas in
the ground will not be produced because it cannot overcome the
higher gathering system pressure. In contrast, if field
compression is installed, then a well can continue delivering
production that otherwise would not be produced.
Natural
Gas Processing and Transportation
The principal component of natural gas is methane, but most
natural gas also contains varying amounts of NGLs including
ethane, propane, normal butane, isobutane and natural gasoline.
NGLs have economic value and are utilized as a feedstock in the
petrochemical and oil refining industries or directly as
heating, engine or industrial fuels. Long-haul natural gas
pipelines have specifications as to the maximum NGL content of
the gas to be shipped. In order to meet quality standards for
long-haul pipeline transportation, natural gas collected through
a gathering system may need to be processed to separate
hydrocarbon liquids from the natural gas that can have higher
values as NGLs. NGLs are typically recovered by cooling the
natural gas until the NGLs become separated through
condensation. Cryogenic recovery methods are processes where
this is accomplished at temperatures lower than minus
150°F. These methods provide higher NGL recovery yields.
After being extracted from natural gas, the NGLs are typically
transported via NGL pipelines or trucks to a fractionator for
separation of the NGLs into their component parts.
In addition to NGLs, natural gas collected through a gathering
system may also contain impurities, such as water, sulfur
compounds, nitrogen or helium, which must also be removed to
meet the quality standards for long-haul pipeline
transportation. As a result, a natural gas processing plant will
typically provide ancillary services such as dehydration and
condensate separation prior to processing. Dehydration removes
water from the natural gas stream, which can form ice when
combined with natural gas and cause corrosion when combined with
carbon dioxide or hydrogen sulfide. Natural gas with a carbon
dioxide or hydrogen sulfide content higher than permitted by
pipeline quality standards requires treatment with chemicals
called amines at a separate treatment plant prior to processing.
Condensate separation involves the removal of hydrocarbons from
the natural gas stream. Once the condensate has been removed, it
may be stabilized for transportation away from the processing
plant via truck, rail or pipeline.
Wholesale
Propane Logistics Overview
General
We are engaged in wholesale propane logistics in the midwest and
northeastern United States. Wholesale propane logistics covers
the receipt of propane from processing plants, fractionation
facilities and crude oil refineries, the transportation of that
propane by pipeline, rail or ship to terminals and storage
facilities, the storage of propane and the delivery of propane
to retail distributors.
Production
of Propane
Propane is extracted from the natural gas stream at processing
plants, separated from NGLs at fractionation facilities or
separated from crude oil during the refining process. Most of
the propane that is consumed in the United States is produced at
processing plants, fractionation facilities and refineries
located in the mid-continent, along the Texas and Louisiana Gulf
Coast or in foreign locations, particularly Canada, the North
Sea, East Africa and the Middle East. There are limited
processing plants and fractionation facilities in the
northeastern United States, and propane production is limited.
Transportation
While significant refinery production exists, propane delivery
ratios are limited and refineries sometimes use propane as
internal fuel during winter months. As a result, the
northeastern United States is an importer of propane, relying
almost exclusively on pipeline, marine and rail sources for
incoming supplies.
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Storage
Independent terminal operators and wholesale distributors, such
as us, own, lease or have access to propane storage terminals
that receive supplies via pipeline, ship or rail. Generally,
inventories in the propane storage facilities increase during
the spring and summer months for delivery to customers during
the fall and winter heating season when demand is typically at
its peak.
Delivery
Often, upon receipt of propane at marine, rail and pipeline
terminals, product is delivered to customer trucks or is
stored in tanks located at the terminals or in off-site bulk
storage facilities for future delivery to customers. Most
terminals and storage facilities have a tanker truck loading
facility commonly referred to as a rack. Often
independent retailers will rely on independent trucking
companies to pick up propane at the rack and transport it to the
retailer at its location. Each truck has transport capacity of
generally between 9,500 and 12,500 gallons of propane.
Natural
Gas Services Segment
General
Our Natural Gas Services segment consists of a geographically
diverse complement of assets and ownership interests that
provide a varying array of wellhead to market services for our
producer customers. These services include gathering,
compressing, treating, processing, fractionating and
transporting natural gas; however, we do not offer all services
in every location. These assets are positioned in areas with
active drilling programs and opportunities for both organic
growth and readily integrated acquisitions. We operate in seven
states in the continental United States: Arkansas, Colorado,
Louisiana, Michigan, Oklahoma, Texas and Wyoming. The assets in
these states include our Northern Louisiana system, our Southern
Oklahoma system, our equity interests in Discovery and East
Texas, our 70% operating interest in the Collbran system, our
Douglas system, and our Michigan gathering and treating assets.
The Southern Oklahoma and East Texas assets provide operating
synergies and opportunities for growth in conjunction with DCP
Midstream. This geographic diversity helps to mitigate our
natural gas supply risk in that we are not tied to one natural
gas producing area. We believe our current geographic mix of
assets will be an important factor for maintaining overall
volumes and cash flow for this segment.
Our Natural Gas Services segment consists of approximately
4,500 miles of pipe, five processing plants, a treating
plant, two NGL fractionation facilities and over 120,000
horsepower of compression capability. The processing plants that
service our natural gas gathering systems include one cryogenic
facility with approximately
115 MMcf/d
of processing capacity, two refrigeration style facilities with
approximately
165 MMcf/d
of processing capacity and two cryogenic facilities owned via
equity interests with our proportionate share at approximately
435 MMcf/d
of processing capacity. Further, our Minden and Discovery
processing facilities both have ethane rejection capabilities
that serve to optimize value of the gas stream. The combined NGL
production from our processing facilities is in excess of
20,000 barrels per day and is delivered and sold into
various NGL takeaway pipelines or trucked out.
The volume throughput on our assets is in excess of
830 MMcf/d
from over 3,600 individual receipt points and originates from a
diversified mix of natural gas producing companies. Our Southern
Oklahoma, East Texas, Northern Louisiana, Discovery and Collbran
systems each have significant customer acreage dedications that
will continue to provide opportunities for growth as those
customers execute their drilling plans over time. Our gathering
systems also attract new natural gas volumes through numerous
smaller acreage dedications and also by contracting with
undedicated producers who are operating in or around our
gathering footprint.
We have primarily a mix of percent-of-proceeds and fee-based
contracts with our producing customers in our Natural Gas
Services segment. Contracts at Minden, Southern Oklahoma,
Douglas, Discovery and East Texas have a large component of
percent-of-proceeds contracts due to the processing value of the
gas streams at each of these systems. In addition, Discovery may
also generate a portion of its earnings through keep-
8
whole contracts. The Pelico, Ada, Minden, Collbran and Michigan
systems are predominantly supported by fee-based contracts. This
diverse contract mix is a result of contracting patterns that
are largely a result of the competitive landscape in each
particular geographic area.
In total, our natural gas gathering systems have the ability to
deliver gas into over 20 downstream transportation pipelines and
markets. Many of our outlets transport gas to premium markets in
the eastern United States, further enhancing the competitiveness
of our commercial efforts in and around our natural gas
gathering systems.
Gathering
Systems, Processing Plants and Transportation
Systems
Following is operating data for our systems:
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Approximate
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Gas Gathering
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Approximate
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2008 Operating Data
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and
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Partnership
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Plants
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Fractionator
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Net Plant
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Natural Gas
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NGL
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Transmission
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Operated
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Operated
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Operated by
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Capacity
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Throughput
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Production
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System
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System (Miles)
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Plants
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by Others
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Others
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(MMcf/d)
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(MMcf/d)(a)
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(Bbls/d)(a)
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Minden
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725
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1
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115
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83
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4,619
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Ada
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130
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1
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45
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62
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165
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Pelico
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600
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171
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Southern Oklahoma (Lindsay)
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225
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18
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2,203
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Collbran
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30
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1
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120
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90
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486
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Douglas
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1,320
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16
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1,025
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Michigan
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265
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75
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Discovery
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280
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1
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1
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240
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(b)
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170
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(b)
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4,703
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(b)
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East Texas
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900
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1
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1
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195
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(b)
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153
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(b)
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7,458
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(b)
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Total
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4,475
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3
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2
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2
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715
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838
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20,659
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(a) |
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Represents total volumes for 2008 divided by 366 days. |
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(b) |
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For Discovery and East Texas, includes our 40% and 25%
proportionate share, respectively, of the approximate net plant
capacity, natural gas throughput and NGL production. |
The Northern Louisiana natural gas gathering system includes the
Minden, Ada and Pelico systems, which gather natural gas from
producers at approximately 670 receipt points and deliver it for
processing to the processing plants. The Minden gathering system
also delivers NGLs produced at the Minden processing plant to
our 45% owned Black Lake pipeline. There are 26 compressor
stations located within the system, comprised of 60 units
with an aggregate of approximately 70,000 horsepower. Through
our Northern Louisiana system, we offer producers and customers
wellhead-to-market services. The Northern Louisiana system has
numerous market outlets for the natural gas we gather, including
several intrastate and interstate pipelines, major industrial
end-users and major power plants. The system is strategically
located to facilitate the transportation of natural gas from
Texas and northern Louisiana to pipeline connections linking to
markets in the eastern and northeastern areas of the United
States.
The Minden processing plant is a cryogenic natural gas
processing and treating plant located in Webster Parish,
Louisiana. This processing plant has amine treating and ethane
recovery and rejection capabilities such that we can recover
approximately 80% of the ethane contained in the natural gas
stream. In addition, the processing plant is able to reject the
majority of the ethane when justified by market economics. This
processing flexibility enables us to maximize the value of
ethane for our customers. In 2002, we upgraded the Minden
processing plant to enable greater ethane recovery and rejection
capabilities. As part of that project, we reached an agreement
with certain customers to receive 100% of the realized margin
attributable to the incremental value of ethane recovered as an
NGL from the natural gas stream when appropriate market
conditions exist. The defined return on the initial investment
for this ethane recovery upgrade was reached in 2007.
9
The Ada gathering system is located in Bienville and Webster
parishes in Louisiana and the Ada processing plant is a
refrigeration natural gas processing plant located in Bienville
Parish, Louisiana. This low pressure gathering system compresses
and processes natural gas for our producing customers and
delivers residue gas into our Pelico intrastate system. We then
sell the NGLs to third-parties who truck them from the plant
tailgate.
The Pelico system is an intrastate natural gas gathering and
transportation pipeline that gathers and transports natural gas
that does not require processing from producers in the area at
approximately 450 meter locations. Additionally, the Pelico
system transports processed gas from the Minden and Ada
processing plants and natural gas supplied from third party
interstate and intrastate natural gas pipelines. The Pelico
system also receives natural gas produced in Texas through its
interconnect with other pipelines that transport natural gas
from Texas into western Louisiana.
The Southern Oklahoma system consists of 9,500 horsepower of
compression, and approximately 350 receipt points, and is
located in the Golden Trend area of McClain, Garvin and Grady
counties in southern Oklahoma. The system was acquired from
Anadarko Petroleum Corporation in May 2007 and is adjacent to
assets owned by DCP Midstream, LLC. Currently, natural gas
gathered by the system is delivered to the Oneok Maysville plant
for processing; however, we will have the ability in 2009 to
process the gas at a DCP Midstream, LLC processing plant to
enhance our processing economics. The current Maysville
connection provides marketing flexibility to multiple pipelines
and access to local liquid markets using Oneoks
fractionation capabilities.
The Collbran system has assets in the southern Piceance Basin
that gather natural gas at high pressure from over 20,000
dedicated acres in western Colorado, and a refrigeration natural
gas processing plant with a current capacity of
120 MMcf/d.
Our 70% operating interest in the Collbran system was acquired
from DCP Midstream, LLC in August 2007 following its acquisition
of MEG. The remaining interests in the joint venture are held by
Occidental Petroleum Corporation (25%) and Delta Petroleum
Corporation (5%), who are also producers on the system. The
processing plant was expanded in 2008 to an operating capacity
to
120 MMcf/d
to accommodate expected increases in volumes. The Collbran
system is currently undergoing a further expansion, which is
scheduled to be completed in the third quarter of 2009,
consisting of an additional
24-inch
pipeline loop and compression at the Anderson Gulch site. The
expansion, expected to be completed in 2009, would increase the
pipeline capacity to over
200 MMcf/d
and enable gas deliveries to the Meeker Plant through a
downstream connection with Enterprise Products Partners LP,
which is also expanding its system feeding its plant. The
Collbran system is designed to ultimately have throughput
capacity of over
600 MMcf/d
depending on future production growth.
The Douglas system has natural gas gathering pipelines that
cover more than 4,000 square miles in Wyoming with over
1,300 miles of pipe. The system gathers primarily rich
casing-head gas from oil wells at low pressure from
approximately 650 receipt points and delivers the gas to a third
party for processing under a fee agreement. The Douglas system
has approximately 16,000 horsepower of compression to maintain
our low pressure gathering service. The Douglas system was
acquired from DCP Midstream, LLC in August 2007 following its
acquisition of MEG.
We acquired MPP on October 1, 2008. These assets consist of
five natural gas treating plants and an approximately
155-mile gas
gathering pipeline system with throughput capacity of
330 MMcf/d;
an approximately
55-mile
residue gas pipeline; a 75% interest in Jackson Pipeline
Company, a partnership owning an approximately
25-mile
residue pipeline; and a 44% interest in the Litchfield pipeline,
a 30-mile
pipeline whereby we lease our undivided interest to ANR Pipeline
Company through the use of a direct financing lease expiring in
2031.
We have a 40% equity interest in Discovery and the remaining 60%
is owned by Williams Partners, L.P. Discovery owns (1) a
natural gas gathering and transportation pipeline system located
primarily off the coast of Louisiana in the Gulf of Mexico, with
six delivery points connected to major interstate and intrastate
pipeline systems; (2) a cryogenic natural gas processing
plant in Larose, Louisiana; (3) a fractionator in Paradis,
Louisiana and (4) an NGL pipeline connecting the gas
processing plant to the fractionator. The Discovery system,
operated by the Williams Companies, offers a full range of
wellhead-to-market services to
10
both onshore and offshore natural gas producers. The assets are
primarily located in the eastern Gulf of Mexico and Lafourche
Parish, Louisiana. The Discovery system is able to reject the
majority of the ethane when justified by market economics.
Discovery is managed by a two-member management committee,
consisting of one representative from each owner. The members of
the management committee have voting power corresponding to
their respective ownership interests in Discovery. All actions
and decisions relating to Discovery require the unanimous
approval of the owners except for a few limited situations.
Discovery must make quarterly distributions of available cash
(generally, cash from operations less required and discretionary
reserves) to its owners. The management committee, by majority
approval based on the ownership percentage represented, will
determine the amount of the distributions. In addition, the
owners are required to offer to Discovery all opportunities to
construct pipeline laterals within an area of
interest.
Additionally, Discovery has signed definitive agreements with
Chevron Corporation, Total E&P USA, Inc., and StatoilHydro
ASA to construct an approximate
34-mile
gathering pipeline lateral to connect Discoverys existing
pipeline system to these producers production facilities
for the Tahiti prospect in the deepwater region of the Gulf of
Mexico. The Tahiti pipeline lateral expansion has a design
capacity of approximately
200 MMcf/d.
Chevron expects first production to commence in the third
quarter of 2009. In conjunction with our acquisition of a 40%
limited liability company interest in Discovery from DCP
Midstream, LLC in July 2007, we entered into a letter agreement
with DCP Midstream, LLC whereby DCP Midstream, LLC made capital
contributions to us as reimbursement for remaining costs for the
Tahiti pipeline lateral expansion, which were substantially
completed in 2008.
We own a 25% interest in East Texas (the remaining 75% is owned
by DCP Midstream, LLC), which gathers, transports, treats,
compresses and processes natural gas and NGLs. The East Texas
facility may also fractionate NGL production, which can be
marketed at nearby petrochemical facilities. The operations,
located near Carthage, Texas, include a natural gas processing
complex that is connected to its gathering system, as well as
third party gathering systems. The complex includes the Carthage
Hub, which delivers residue gas to interstate and intrastate
pipelines. The Carthage Hub acts as a key exchange point for the
purchase and sale of residue gas in the eastern Texas region.
The East Texas system consists of approximately 900 miles
of pipe, processing capacity of
780 MMcf/d,
fractionation capacity of 11,000 Bbls/d, over 25,000
horsepower of compression and serves over 1,500 receipt points
in and around its geographic footprint.
East Texas is managed by a four-member management committee,
consisting of two representatives from each owner. The members
of the management committee have voting power corresponding to
their respective ownership interests in East Texas. Most
significant actions relating to East Texas require the unanimous
approval of both owners. East Texas must make quarterly
distributions of available cash (generally, cash from operations
less required and discretionary reserves) to its owners. The
management committee, by majority approval, will determine the
amount of the distributions.
Natural
Gas and NGL Markets
The Northern Louisiana system has numerous market outlets for
the natural gas that we gather on the system. Our natural gas
pipelines connect to the Perryville Market Hub, a natural gas
marketing hub that provides connection to four intrastate or
interstate pipelines, including pipelines owned by Southern
Natural Gas Company, Texas Gas Transmission, LLC, CenterPoint
Energy Mississippi River Transmission Corporation and
CenterPoint Energy Gas Transmission Company. In addition, our
natural gas pipelines in northern Louisiana also have access to
gas that flows through pipelines owned by Texas Eastern
Transmission, LP, Crosstex LIG, LLC, Gulf South Pipeline
Company, Tennessee Natural Gas Company and Regency Intrastate
Gas, LLC. The Northern Louisiana system is also connected to
eight major industrial end-users and makes deliveries to three
power plants.
The NGLs extracted from the natural gas at the Minden processing
plant are delivered to our 45%-owned Black Lake pipeline through
our wholly-owned approximately
9-mile
Minden NGL pipeline. The Black Lake pipeline delivers NGLs to
Mt. Belvieu. The NGLs extracted from natural gas at the Ada
processing plant are sold at market index prices to affiliates
and are delivered to third parties trucks at the tailgate
of the plant.
11
The Southern Oklahoma system has access through the Maysville
processing plant to deliver gas into mid-continent transmission
pipelines such as Oneok Gas Transportation and Southern Star
Central Gas Pipelines, among others. When the Southern Oklahoma
system delivers into the DCP Midstream, LLC owned processing
plant(s) in the second quarter of 2009, a similar mix of
mid-continent pipelines and markets will be available to our
customers. NGLs produced from this system are delivered to Oneok
Gas Transportation.
The Collbran system in western Colorado delivers gas into the
TransColorado Gas Transmission interstate pipeline and to the
Rocky Mountain Natural Gas LDC. The Douglas system in the Powder
River basin in northeastern Wyoming delivers to the Kinder
Morgan Interstate Gas Transmission interstate pipeline. The NGLs
from the Collbran system are trucked off site by third party
purchasers, while NGLs on the Douglas system are transported on
the ConocoPhillips owned Powder River Pipeline.
The Michigan Antrim gas gathering and treating system delivers
Antrim Shale gas to the South Chester Treating Complex. Antrim
Shale natural gas requires treating in order to meet downstream
gas pipeline quality specifications. The treated gas is
transported to MichCon Gathering system from the tailgate of the
plant. The Bay Area pipeline delivers fuel gas to a third party
power plant owned by Consumers Energy. The Jackson Pipeline is
operated by Consumers Energy and connects several intrastate
pipelines with the Eaton Rapids gas storage facility. The
Litchfield pipeline is operated by ANR Pipeline Company and
facilitates receipts or deliveries between ANR Pipeline Company
and the Eaton Rapids storage facility. All Michigan assets were
acquired from MPP on October 1, 2008.
The Discovery assets have access to downstream pipelines and
markets including Texas Eastern Transmission Company,
Bridgeline, Gulf South Pipeline Company, Transcontinental Gas
Pipeline Company, Columbia Gulf Transmission and Tennessee Gas
Pipeline Company, among others. The NGLs are fractionated at the
Paradis fractionation facilities and delivered downstream to
third-party purchasers. The third party purchasers of the
fractionated NGLs consist of a mix of local petrochemical
facilities and wholesale distribution companies for the ethane
and propane components, while the butanes and natural gasoline
are delivered and sold to pipelines that transport product to
the storage and distribution center near Napoleonville,
Louisiana or other similar product hub.
The East Texas system delivers gas primarily to the Carthage Hub
which delivers residue gas to ten different interstate and
intrastate pipelines including Centerpoint Energy Gas
Transmission, Texas Gas Transmission, Tennessee Gas Pipeline
Company, Natural Gas Pipeline Company of America, Gulf South
Pipeline Company, Enterprise and others. Certain of the lighter
NGLs, consisting of ethane and propane, are fractionated at the
East Texas facility and sold to regional petrochemical
purchasers. The remaining NGLs, including butanes and natural
gasoline, are purchased by DCP Midstream, LLC and shipped on the
Panola NGL pipeline to Mont Belvieu for fractionation and sale.
Customers
and Contracts
The primary suppliers of natural gas to our Natural Gas Services
segment are a broad cross-section of the natural gas producing
community. We actively seek new producing customers of natural
gas on all of our systems to increase throughput volume and to
offset natural declines in the production from connected wells.
We obtain new natural gas supplies in our operating areas by
contracting for production from new wells, by connecting new
wells drilled on dedicated acreage and by obtaining natural gas
that has been directly received or released from other gathering
systems.
We had no third-party customers in our Natural Gas Services
segment that accounted for greater than 10% of our revenues.
Our contracts with our producing customers in our Natural Gas
Services segment are primarily a mix of commodity sensitive
percent-of-proceeds contracts and non-commodity sensitive
fee-based contracts. Generally, the initial term of these
purchase agreements is for three to five years or, in some
cases, the life of the lease. The largest percentage of volume
at Minden, Southern Oklahoma, Douglas and East Texas are
processed under percent-of-proceeds contracts. Discovery has
percent-of-proceeds contracts and fee-based contracts, as well
as some keep-whole contracts. The majority of the contracts for
our Pelico, Ada, Collbran and Michigan
12
systems are fee-based agreements. Our gross margin generated
from percent-of-proceeds contracts is directly correlated to the
price of natural gas, NGLs and condensate.
The midstream natural gas industry is cyclical, with the
operating results of companies in the industry significantly
affected by the prevailing price of NGLs, which in turn has been
generally correlated to the price of crude oil, except in recent
periods, when NGL pricing has been at a greater discount to
crude oil pricing. Although the prevailing price of residue
natural gas has less short-term significance to our operating
results than the price of NGLs, in the long term the growth and
sustainability of our business depends on natural gas prices
being at levels sufficient to provide incentives and capital for
producers to increase natural gas exploration and production.
The prices of NGLs, crude oil and natural gas can be extremely
volatile for periods of time, and may not always have a close
correlation. Changes in the correlation of the price of NGLs and
crude oil may cause our commodity price sensitivities to vary.
To minimize potential future commodity-based pricing and cash
flow volatility, we have entered into a series of derivative
financial instruments. As a result of these transactions, we
have mitigated a significant portion of our expected natural
gas, NGL and condensate commodity price risk relating to the
equity volumes associated with our gathering and processing
operations through 2013.
Discoverys wholly owned subsidiary, Discovery Gas
Transmission, owns the mainline and the Federal Energy
Regulatory Commission, or FERC-regulated laterals, which
generate revenues through a tariff on file with the FERC for
several types of service: traditional firm transportation
service with reservation fees (although no current shippers have
elected this service); firm transportation service on a
commodity basis with reserve dedication; and interruptible
transportation service. In addition, for any of these general
services, Discovery Gas Transmission has the authority to
negotiate a specific rate arrangement with an individual shipper
and has several of these arrangements currently in effect.
Competition
Competition in our Natural Gas Services segment is highly
competitive in our markets and includes major integrated oil and
gas companies, interstate and intrastate pipelines, and
companies that gather, compress, treat, process, transport
and/or
market natural gas. Competition is often the greatest in
geographic areas experiencing robust drilling by producers and
during periods of high commodity prices for crude oil, natural
gas and/or
natural gas liquids. Competition is also increased in those
geographic areas where our commercial contracts with our
customers are shorter in length of term and therefore must be
renegotiated on a more frequent basis.
Wholesale
Propane Logistics Segment
General
We operate a wholesale propane logistics business in the states
of Connecticut, Maine, Massachusetts, New Hampshire, New York,
Ohio, Pennsylvania, Rhode Island and Vermont.
Due to our multiple propane supply sources, annual and long-term
propane supply purchase arrangements, significant storage
capabilities, and multiple terminal locations for wholesale
propane delivery, we are generally able to provide our retail
propane distribution customers with reliable, low cost
deliveries and greater volumes of propane during periods of
tight supply such as the winter months. We believe these factors
generally allow us to maintain favorable relationships with our
customers.
These factors have allowed us to remain a supplier to many of
the large retail distributors in the northeastern United States.
As a result, we serve as the baseload provider of propane supply
to many of our retail propane distribution customers.
We manage our wholesale propane margins by selling propane to
retail propane distributors under annual sales agreements
negotiated each spring that specify floating price terms that
provide us a margin in excess of our floating index-based supply
costs under our supply purchase arrangements. In the event that
a retail propane distributor desires to purchase propane from us
on a fixed price basis, we sometimes enter into fixed price
sales agreements with terms of generally up to one year, and we
manage this commodity price risk by entering into either
offsetting physical purchase agreements or financial derivative
instruments, with either
13
DCP Midstream, LLC or third parties, that generally match the
quantities of propane subject to these fixed price sales
agreements. The financial derivatives are accounted for using
mark-to-market accounting. Our portfolio of multiple supply
sources and storage capabilities allows us to actively manage
our propane supply purchases and to lower the aggregate cost of
supplies. Based on the carrying value of our inventory, timing
of inventory transactions and the volatility of the market value
of propane, we have historically and may continue to
periodically recognize non-cash lower of cost or market
inventory adjustments. In addition, we may, on occasion, use
financial derivatives to manage the value of our propane
inventories.
Pipeline deliveries to the northeast market in the winter season
are generally at capacity and competing pipeline dependent
terminals can have supply constraints or outages during peak
market conditions. Our system of terminals has substantial
excess capacity, which provides us with opportunities to
increase our volumes with minimal additional cost. Additionally,
we constructed a propane pipeline terminal located in Midland,
Pennsylvania that became operational in May 2007, and we are
actively seeking new terminals through acquisition or
construction to expand our distribution capabilities, subject to
the availability of capital.
Our
Terminals
Our operations include six propane rail terminals with aggregate
storage capacity of 25 MBbls, one of which was idled in
2007 to consolidate our operations, one propane marine terminal
with storage capacity of 410 MBbls, one propane pipeline
terminal with storage capacity of 56 MBbls and access to
several open access pipeline terminals. We own our rail
terminals and lease the land on which the terminals are situated
under long-term leases, except for the York terminal where we
own the land. The marine terminal is leased on a long-term lease
agreement. Each of our rail terminals consist of two to three
propane tanks with capacity of between 120,000 and 270,000
gallons for storage, and two high volume loading racks for
loading propane into trucks. Our aggregate truck-loading
capacity is approximately 400 trucks per day. We could expand
each of our terminals loading capacity by adding a third
loading rack to handle future growth. High volume submersible
pumps are utilized to enable trucks to fully load within 15
minutes. Each facility also has the ability to unload multiple
railcars simultaneously. We have numerous railcar leases that
allow us to increase our storage and throughput capacity as
propane demand increases. Each terminal relies on leased rail
trackage for the storage of the majority of its propane
inventory in these leased railcars. These railcars mitigate the
need for larger numbers of fixed storage tanks and reduce
initial capital needs when constructing a terminal. Each railcar
holds approximately 30,000 gallons of propane.
We are also actively seeking to expand and favorably position
our wholesale propane distribution business into the upper
Midwest and Mid-Atlantic states, and have constructed a propane
pipeline terminal in western Pennsylvania that became
operational in May 2007.
Propane
Supply
Our wholesale propane business has a strategic network of supply
arrangements under annual and multi-year agreements under
index-based pricing. The remaining supply is purchased on annual
or month-to-month terms to match our anticipated sale
requirements. During 2008, our primary suppliers of propane
included a subsidiary of DCP Midstream, LLC, Aux Sable Liquid
Products LP and Spectra Energy. During 2007, our primary
suppliers of propane included Shell International Trading and
Shipping Company, Aux Sable Liquid Products LP and a subsidiary
of DCP Midstream, LLC.
For our rail terminals, we contract for propane at various major
supply points in the United States and Canada, and transport the
product to our terminals under long-term rail commitments, which
provide fixed transportation costs that are subject to
prevailing fuel surcharges. We also purchase propane supply from
natural gas fractionation plants and crude oil refineries
located in the Texas and Louisiana Gulf Coast. Through this
process, we take custody of the propane and either sell it in
the wholesale market or store it at our facilities. For our
marine terminal, we have historically contracted under annual
agreements for delivered shipments of propane. In May 2008, we
entered into a long term contract with Spectra Energy that
offers both product and shipping capabilities. The port where
the marine terminal facility is located has been expanded, and
we can now receive propane supply from larger propane tankers.
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Customers
and Contracts
We typically sell propane to retail propane distributors under
annual sales agreements negotiated each spring that specify
floating price terms that provide us a margin in excess of our
floating index-based supply costs under our supply purchase
arrangements. In the event that a retail propane distributor
desires to purchase propane from us on a fixed price basis, we
sometimes enter into fixed price sales agreements with terms of
generally up to one year. We manage this commodity price risk by
entering into either offsetting physical purchase agreements or
financial derivative instruments, with DCP Midstream, LLC or
third parties that generally match the quantities of propane
subject to these fixed price sales agreements. Our ability to
help our clients manage their commodity price exposure by
offering propane at a fixed price may lead to a larger customer
base. Historically, approximately 75% of the gross margin
generated by our wholesale propane business is earned in the
heating season months of October through April, which
corresponds to the general market demand for propane.
We had no third-party customers in our Wholesale Propane
Logistics segment that accounted for greater than 10% of our
revenues.
Competition
The wholesale propane business is highly competitive in the
upper midwest and northeastern regions of the United States. Our
wholesale propane business competitors include major
integrated oil and gas and energy companies, and interstate and
intrastate pipelines.
NGL
Logistics Segment
General
We operate our NGL Logistics business in the states of Louisiana
and Texas.
Our NGL transportation assets consist of our wholly-owned
approximately
68-mile
Seabreeze intrastate NGL pipeline and our wholly-owned
approximately
39-mile
Wilbreeze intrastate NGL pipeline, both of which are located in
Texas, and a 45% interest in the approximately
317-mile
Black Lake interstate NGL pipeline located in Louisiana and
Texas. These NGL pipelines transport NGLs from natural gas
processing plants to fractionation facilities, a petrochemical
plant and an underground NGL storage facility. In aggregate, our
NGL transportation business has 73 MBbls/d of capacity and
in 2008 average throughput was approximately 31 MBbls/d.
Our pipelines provide transportation services to customers on a
fee basis. Therefore, the results of operations for this
business are generally dependent upon the volume of product
transported and the level of fees charged to customers. The
volumes of NGLs transported on our pipelines are dependent on
the level of production of NGLs from processing plants connected
to our NGL pipelines. When natural gas prices are high relative
to NGL prices, it is less profitable to recover NGLs from
natural gas because of the higher value of natural gas compared
to the value of NGLs. As a result, we have experienced periods
in the past, and will likely experience periods in the future,
when higher natural gas prices reduce the volume of NGLs
produced at plants connected to our NGL pipelines.
NGL
Pipelines
Seabreeze and Wilbreeze Pipelines. The
Seabreeze pipeline has capacity of 33 MBbls/d and for 2008
average throughput on the pipeline was approximately
17 MBbls/d. The Seabreeze pipeline was put into service in
2002 to deliver NGLs to a large processing plant with capacity
of approximately
340 MMcf/d
located in Matagorda County, and a NGL pipeline. The Seabreeze
pipeline also delivered to a second plant, which was closed
during 2008. The Seabreeze pipeline is the sole NGL pipeline for
one processing plant and is the only delivery point for two NGL
pipelines. One third party NGL pipeline transports NGLs from
five natural gas processing plants located in southeastern Texas
that have aggregate processing capacity of approximately
1.6 Bcf/d. Three of these processing plants are owned by
DCP Midstream, LLC. In total seven processing plants produce
NGLs that flow into the Seabreeze pipeline from processed
natural gas produced in
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southern Texas and offshore in the Gulf of Mexico. The Seabreeze
pipeline delivers the NGLs it receives from these sources to a
fractionator and a storage facility. We completed construction
of our Wilbreeze pipeline in December 2006. Current capacity of
the Wilbreeze pipeline is 11 MBbls/d and average throughput
on the pipeline was approximately 6 MBbls/d for 2008.
Black Lake Pipeline. The Black Lake pipeline
has capacity of 40 MBbls/d and for 2008, average throughput
on the Black Lake pipeline at our 45% interest was approximately
8 MBbls/d. The Black Lake pipeline was constructed in 1967
and delivers NGLs from processing plants in northern Louisiana
and southeastern Texas to fractionation plants at Mont Belvieu
on the Texas Gulf Coast. The Black Lake pipeline receives NGLs
from three natural gas processing plants in northern Louisiana,
including our Minden plant, Regency Intrastate Gas, LLCs
Dubach processing plant and Chesapeake Energy Corporations
Black Lake processing plant. The Black Lake pipeline is the sole
NGL pipeline for all of these natural gas processing plants in
northern Louisiana, as well as the Ceritas South Raywood
processing plant located in southeastern Texas, and also
receives NGLs from XTO Energy Inc.s Cotton Valley
processing plant. In addition, the Black Lake pipeline receives
NGLs from a natural gas processing plant located in southeastern
Texas.
There are currently five significant active shippers on the
pipeline, with DCP Midstream, LLC historically being the
largest, representing approximately 47% of total throughput in
2008. The Black Lake pipeline generates revenues through a
FERC-regulated tariff, and the average rate per barrel was $1.00
in 2008, $0.95 in 2007 and $0.94 in 2006.
Black Lake is a partnership that is operated by and 50% owned by
BP PLC. Black Lake is required by its partnership agreement to
make monthly cash distributions equal to 100% of its available
cash for each month, which is defined generally as receipts plus
reductions in cash reserves less disbursements and increases in
cash reserves. In anticipation of a pipeline integrity project,
Black Lake suspended making monthly cash distributions in
December 2004 in order to reserve cash to pay the expenses of
this project. This project was completed and cash distributions
resumed during 2008.
Customers
and Contracts
The Wilbreeze pipeline is supported by an NGL product dedication
agreement with DCP Midstream, LLC.
Effective December 1, 2005, we entered into a contractual
arrangement with a subsidiary of DCP Midstream, LLC that
provides that DCP Midstream, LLC will purchase the NGLs that
were historically purchased by us, and DCP Midstream, LLC will
pay us to transport the NGLs pursuant to a fee-based rate that
will be applied to the volumes transported. We have entered into
this fee-based contractual arrangement with the objective of
generating approximately the same operating income per barrel
transported that we realized when we were the purchaser and
seller of NGLs. We do not take title to the products transported
on the NGL pipelines; rather, the shipper retains title and the
associated commodity price risk. DCP Midstream, LLC is the sole
shipper on the Seabreeze pipeline under a long-term
transportation agreement. The Seabreeze pipeline only collects
fee-based transportation revenue under this agreement. DCP
Midstream, LLC receives its supply of NGLs that it then
transports on the Seabreeze pipeline under an NGL purchase
agreement with Williams. Under this agreement, Williams has
dedicated all of their respective NGL production from this
processing plant to DCP Midstream, LLC. DCP Midstream, LLC has a
sales agreement with Formosa. Additionally, DCP Midstream, LLC
has a transportation agreement with TEPPCO Partners, L.P. that
covers all of the NGL volumes transported on TEPPCO Partners,
L.P.s South Dean NGL pipeline for delivery to the
Seabreeze pipeline.
We had no third-party customers in our NGL Logistics segment
that accounted for greater than 10% of our revenues.
Safety
and Maintenance Regulation
We are subject to regulation by the United States Department of
Transportation, or DOT, under the Hazardous Liquids Pipeline
Safety Act of 1979, as amended, referred to as the Hazardous
Liquid Pipeline
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Safety Act, and comparable state statutes with respect to
design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The Hazardous
Liquid Pipeline Safety Act covers petroleum and petroleum
products, including NGLs and condensate, and requires any entity
that owns or operates pipeline facilities to comply with such
regulations, to permit access to and copying of records and to
file certain reports and provide information as required by the
United States Secretary of Transportation. These regulations
include potential fines and penalties for violations. We believe
that we are in material compliance with these Hazardous Liquid
Pipeline Safety Act regulations.
We are also subject to the Natural Gas Pipeline Safety Act of
1968, as amended, or NGPSA, and the Pipeline Safety Improvement
Act of 2002. The NGPSA regulates safety requirements in the
design, construction, operation and maintenance of gas pipeline
facilities while the Pipeline Safety Improvement Act establishes
mandatory inspections for all United States oil and natural gas
transportation pipelines in high-consequence areas within
10 years. The DOT has developed regulations implementing
the Pipeline Safety Improvement Act that requires pipeline
operators to implement integrity management programs, including
more frequent inspections and other safety protections in areas
where the consequences of potential pipeline accidents pose the
greatest risk to people and their property. We currently
estimate we will incur costs of approximately $2.0 million
between 2009 and 2013 to implement integrity management program
testing along certain segments of our natural gas transmission
and NGL pipelines. This does not include the costs, if any, of
repair, remediation, preventative or mitigating actions that may
be determined to be necessary as a result of the testing
program. DCP Midstream, LLC agreed to indemnify us for up to
$5.3 million of our pro rata share of any capital
contributions associated with repairing the Black Lake pipeline
that are determined to be necessary as a result of the pipeline
integrity testing. We anticipate repairs of approximately
$0.8 million on the pipeline, which will be funded directly
from Black Lake. We will not make contributions to Black Lake to
cover these expenses.
States are largely preempted by federal law from regulating
pipeline safety but may assume responsibility for enforcing
intrastate pipeline regulations at least as stringent as the
federal standards. In practice, states vary considerably in
their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which
we or the entities in which we own an interest operate. Our
natural gas transmission and regulated gathering pipelines have
ongoing inspection and compliance programs designed to keep the
facilities in compliance with pipeline safety and pollution
control requirements.
In addition, we are subject to the requirements of the federal
Occupational Safety and Health Act, or OSHA, and comparable
state statutes, whose purpose is to protect the health and
safety of workers, both generally and within the pipeline
industry. In addition, the OSHA hazard communication standard,
the Environmental Protection Agency, or EPA, community
right-to-know regulations under Title III of the federal
Superfund Amendment and Reauthorization Act and comparable state
statutes require that information be maintained concerning
hazardous materials used or produced in our operations and that
this information be provided to employees, state and local
government authorities and citizens. We and the entities in
which we own an interest are also subject to OSHA Process Safety
Management regulations, which are designed to prevent or
minimize the consequences of catastrophic releases of toxic,
reactive, flammable or explosive chemicals. These regulations
apply to any process which involves a chemical at or above the
specified thresholds, or any process which involves flammable
liquid or gas, pressurized tanks, caverns and wells in excess of
10,000 pounds at various locations. Flammable liquids stored in
atmospheric tanks below their normal boiling point without the
benefit of chilling or refrigeration are exempt. We have an
internal program of inspection designed to monitor and enforce
compliance with worker safety requirements. We believe that we
are in material compliance with all applicable laws and
regulations relating to worker health and safety.
Propane
Regulation
National Fire Protection Association Pamphlets No. 54 and
No. 58, which establish rules and procedures governing the
safe handling of propane, or comparable regulations, have been
adopted as the industry standard in all of the states in which
we operate. In some states these laws are administered by state
agencies, and in others they are administered on a municipal
level. With respect to the transportation of propane by truck,
we
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are subject to regulations promulgated under the Federal Motor
Carrier Safety Act. These regulations cover the transportation
of hazardous materials and are administered by the DOT. We
conduct ongoing training programs to help ensure that our
operations are in compliance with applicable regulations. We
maintain various permits that are necessary to operate our
facilities, some of which may be material to our propane
operations. We believe that the procedures currently in effect
at all of our facilities for the handling, storage and
distribution of propane are consistent with industry standards
and are in compliance in all material respects with applicable
laws and regulations.
FERC
Regulation of Operations
FERC regulation of pipeline gathering and transportation
services, natural gas sales and transportation of NGLs may
affect certain aspects of our business and the market for our
products and services.
Interstate
Natural Gas Pipeline Regulation
The Discovery
105-mile
mainline, approximately 60 miles of laterals and its market
expansion project are subject to regulation by FERC, under the
Natural Gas Act of 1938, or NGA. Natural gas companies may not
charge rates that have been determined not to be just and
reasonable. In addition, the FERCs authority over natural
gas companies that provide natural gas pipeline transportation
services in interstate commerce includes:
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certification and construction of new facilities;
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extension or abandonment of services and facilities;
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maintenance of accounts and records;
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acquisition and disposition of facilities;
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initiation and discontinuation of services;
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terms and conditions of services and service contracts with
customers;
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depreciation and amortization policies;
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conduct and relationship with certain affiliates; and
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various other matters.
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Generally, the maximum filed recourse rates for interstate
pipelines are based on the cost of service including recovery of
and a return on the pipelines actual prudent historical
cost investment. Key determinants in the ratemaking process are
costs of providing service, allowed rate of return and volume
throughput and contractual capacity commitment assumptions. The
maximum applicable recourse rates and terms and conditions for
service are set forth in each pipelines FERC approved
tariff. Rate design and the allocation of costs also can impact
a pipelines profitability. FERC-regulated natural gas
pipelines are permitted to discount their firm and interruptible
rates without further FERC authorization down to the variable
cost of performing service, provided they do not unduly
discriminate.
Tariff changes can only be implemented upon approval by the
FERC. Two primary methods are available for changing the rates,
terms and conditions of service of an interstate natural gas
pipeline. Under the first method, the pipeline voluntarily seeks
a tariff change by making a tariff filing with the FERC
justifying the proposed tariff change and providing notice,
generally 30 days, to the appropriate parties. If the FERC
determines that a proposed change is just and reasonable as
required by the NGA, the FERC will accept the proposed change
and the pipeline will implement such change in its tariff.
However, if the FERC determines that a proposed change may not
be just and reasonable as required by the NGA, then the FERC may
suspend such change for up to five months beyond the date on
which the change would otherwise go into effect and set the
matter for an administrative hearing. Subsequent to any
suspension period ordered by the FERC, the proposed change may
be placed into effect by the company, pending final FERC
approval. In most cases, a proposed rate increase is placed into
effect before a final FERC determination on such rate increase,
and the proposed increase is collected subject to refund (plus
interest). Under the second method, the FERC may, on
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its own motion or based on a complaint, initiate a proceeding
seeking to compel the company to change its rates, terms
and/or
conditions of service. If the FERC determines that the existing
rates, terms
and/or
conditions of service are unjust, unreasonable, unduly
discriminatory or preferential, then any rate reduction or
change that it orders generally will be effective prospectively
from the date of the FERC order requiring this change.
In November 2003, the FERC issued Order 2004 governing the
Standards of Conduct for Transmission Providers (including
natural gas interstate pipelines). These standards provide that
interstate pipeline employees engaged in natural gas
transmission system operations must function independently from
any employees of their energy affiliates and marketing
affiliates and that an interstate pipeline must treat all
transmission customers, affiliated and non-affiliated, on a
non-discriminatory basis, and cannot operate its transmission
system to benefit preferentially, an energy or marketing
affiliate. In addition, Order 2004 restricts access to natural
gas transmission customer data by marketing and other energy
affiliates and provides certain conditions on service provided
by interstate pipelines to their gas marketing and energy
affiliates. In November 2006, the United States Court of Appeals
for the District of Columbia Circuit, or D.C. Circuit, vacated
Order 2004 as that order applies to interstate natural gas
pipelines and remanded that proceeding to the FERC for further
action.
On January 9, 2007, the FERC issued Order 690 in response
to the D.C. Circuits decision. In its Order, the
Commission issued new interim standards of conduct pending the
outcome of a new rulemaking proceeding. The interim standards
only govern the relationship between an interstate pipeline and
its marketing affiliates as opposed to its energy affiliates,
the latter being a much broader category as originally set forth
in Order 2004. As a result, the Commission effectively
repromulgated on a temporary basis the Standards of
Conduct first issued in Order 497 in 1992, while it considers
its course of action to address the courts decision on a
more permanent basis.
On January 18, 2007, the FERC issued a Notice of Proposed
Rulemaking or 2007 NOPR in Docket
No. RM07-1
wherein it proposes to make permanent its interim standards of
conduct issued in Order 690. The Commission also sought comment
as to whether it should make comparable changes to the electric
industry standards of conduct that were not affected by either
the November 2006 decision by the D.C. Circuit, or by Order 690,
as well as comments regarding certain other electric-related
exceptions to Order 2004. We continue to closely monitor these
proceedings and administer our compliance programs accordingly.
On March 21, 2008, FERC issued an NOPR to revise the
Standards of Conduct to make them clearer and to refocus the
rules on the areas where there is the greatest potential for
affiliate abuse, or 2008 NOPR. The 2008 NOPR replaces the 2007
NOPR. The 2008 NOPR applies the Standards of Conduct to any
interstate natural gas pipeline that conducts transportation
transactions with an affiliate that engages in marketing
functions. The definition of marketing function exempts sales
from gathering and processing facilities.
On October 16, 2008, FERC issued Order No. 717
providing a final rule on the FERC Standards of Conduct that
conforms to the U.S. Court of Appeals Decision. The final
rule applies the Standards of Conduct to interstate natural gas
pipelines that conduct transportation transactions with an
affiliate that engages in marketing functions. Under the final
rule, interstate pipeline transmission information is restricted
from being disclosed to the affiliates marketing function
employees. The definition of marketing function employees is
limited to those employees engaged on a day-to-day basis in the
sale for resale of natural gas in interstate commerce. The FERC
Standards of Conduct do not apply to Discovery under the final
rule.
The Outer Continental Shelf Lands Act, or OCSLA, requires that
all pipelines operating on or across the outer continental
shelf, or OCS, provide open access, non-discriminatory
transportation service. In an effort to heighten its oversight
of transportation on the OCS, the FERC attempted to promulgate
reporting requirements with respect to OCS transportation, but
the regulations were struck down as ultra vires by a federal
district court, which decision was affirmed by the D.C. Circuit
in October 2003. The FERC withdrew those regulations in March
2004. Subsequently, in April 2004, the Minerals Management
Service, or MMS, initiated an inquiry into whether it should
amend its regulations to assure that pipelines provide open and
non-discriminatory access over OCS pipeline facilities. In April
2007, the MMS issued a notice of proposed rulemaking that would
establish a process for a shipper transporting oil or gas
production from OCS leases to follow if it
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believes it has been denied open and nondiscriminatory access to
OCS pipelines. However, the proposed rule makes clear that the
MMS will defer to FERC with respect to pipelines subject to
FERCs NGA and Interstate Commerce Act jurisdiction,
stating that the MMS would not consider complaints regarding a
FERC pipeline that, for example, originates from a lease on the
OCS and then transports production onshore to an adjacent state.
The MMS has also proposed a regulation providing for civil
penalties of up to $10,000 per day for violations of the
OCSLAs open and nondiscriminatory access requirements. On
June 18, 2008, the MMS issued a final rule regarding open
and nondiscriminatory access to pipelines on the OCS that is
generally consistent with the NOPR. The final rule did institute
a time limit of two years from the time of the denial of open
access for initiating a formal complaint. The final rule is
effective August 18, 2008. We do not expect that the final
rule will affect our OCS operations.
On July 19, 2007, FERC issued a proposed policy statement
regarding the appropriate composition of proxy groups for
purposes of determining natural gas and oil pipeline equity
returns to be included in cost-of-service based rates. FERC
proposed to permit inclusion of publicly traded partnerships in
the proxy group analysis relating to return on equity
determinations in rate proceedings, provided that the analysis
be limited to actual publicly traded partnership distributions
capped at the level of the pipelines earnings and that
evidence be provided in the form of a multiyear analysis of past
earnings demonstrating a publicly traded partnerships
ability to provide stable earnings over time. On
November 15, 2007, the FERC requested additional comments
regarding the method to be used for creating growth forecasts
for publicly traded partnerships, and FERC held a technical
conference on this issue in January 2008. On April 17,
2008, FERC issued a final policy statement regarding the
appropriate composition of proxy groups. FERC concluded, among
other things, that MLPs should be included in the Return on
Equity or ROE proxy group for both oil and gas pipelines. FERC
established a paper hearing for establishing the ROE for cases
that were pending before FERC. The policy statement could result
in the establishment of a higher ROE in future rate proceedings
but the full effect is uncertain until the policy is applied.
On September 20, 2007, FERC issued a Notice of Inquiry
regarding Fuel Retention Practices of Natural Gas Pipelines
(Fuel NOI). The Fuel NOI inquires whether the current policy
which allows natural gas pipelines to choose between two options
for recovering the costs of fuel and lost and unaccounted for
(LAUF) gas should be changed in favor of a uniform method.
Comments have been filed in response to the Fuel NOI. On
November 20, 2008, FERC terminated this proceeding and
declined making any changes to the fuel retention practices of
natural gas pipelines.
On September 20, 2007, FERC issued a Notice of Proposed
Rulemaking regarding Revisions to Forms, Statements, and
Reporting Requirements for Natural Gas Pipelines (Reporting
NOPR). The Reporting NOPR proposed to require pipelines to
(i) provide additional information regarding their sources
of revenue and amounts included in rate base; (ii) identify
costs related to affiliate transactions; and (iii) provide
additional information regarding incremental facilities, and
discounted and negotiated rates. According to FERC, the changes
would assist pipeline customers and other third parties in
analyzing a pipelines actual return as compared with its
approved rate of return based on publicly filed data. On
March 21, 2008, FERC issued Order No. 710 implementing
revisions to the forms, statements and reporting requirements of
natural gas pipelines. The order is effective on January 1,
2008 and impacts the 2008 FERC Form 2 and subsequent
Form 3-Qs.
The final rule generally adopts the changes provided in the
Reporting NOPR. While the revisions will require additional time
in the development of the report, the impact of the final rule
is not expected to be material to Discovery.
On November 15, 2007, FERC issued a notice of proposed
rulemaking proposing to permit market-based pricing for
short-term capacity releases and to facilitate asset management
arrangements by relaxing FERCs prohibition on tying and on
its bidding requirements for certain capacity releases (Capacity
Release NOPR). FERC proposes to lift the price ceiling for
short-term capacity release transactions of one year or less.
The Capacity Release NOPR is proposed to enable releasing
shippers to offer competitively-priced alternatives to
pipelines negotiated rates and to encourage more efficient
construction of capacity. Under FERCs proposal, it is
possible for the releasing shipper to release the natural gas at
market-based prices while pipelines would still be subject to
the maximum rate cap. On June 19, 2008, FERC issued Order
No. 712 implementing revised capacity release rules that
revised the capacity release regulations consistent with the
Capacity Release NOPR.
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The most significant modification was to allow for capacity
releases of one year or less to be awarded to the highest rate,
without regard to the maximum rate. The impact of this rule to
Discovery should be immaterial.
On December 21, 2007, FERC issued a notice of proposed
rulemaking which proposes to require interstate natural gas
pipelines and certain non-interstate natural gas pipelines to
post capacity, daily scheduled flow information, and daily
actual flow information. On November 20, 2008, FERC issued
Order No. 720, a final rule adopting new regulations that
require certain major non-interstate pipelines and
interstate pipelines to publicly post certain operational and
scheduling information. Interstate pipelines must post the
volumes of no-notice transportation flows at each receipt and
delivery point before 11:30 a.m. central clock time three
days after the day of gas flow. The final rule requires
interstate pipelines to post less information than under the
proposed rule. The final rule does not apply to Discovery.
Additional proposals and proceedings that might affect the
natural gas industry are pending before Congress, the FERC and
the courts. The natural gas industry historically has been
heavily regulated; therefore, there is no assurance that a more
stringent regulatory approach will not be pursued by the FERC
and Congress, especially in light of potential market power
abuse by marketing affiliates of certain pipeline companies
engaged in interstate commerce. In response to this issue,
Congress, in the Energy Policy Act of 2005 (EPACT
2005), and the FERC have implemented requirements to
ensure that energy prices are not impacted by the exercise of
market power or manipulative conduct. EPACT 2005 prohibits the
use of any manipulative or deceptive device or
contrivance in connection with the purchase or sale of
natural gas, electric energy or transportation subject to the
FERCs jurisdiction. The FERC then adopted the Market
Manipulation Rules and the Market Behavior Rules to implement
the authority granted under EPACT 2005. These rules, which
prohibit fraud and manipulation in wholesale energy markets, are
very vague and are subject to broad interpretation. Only two
orders interpreting these rules have been issued to date, and
each of these is subject to further proceedings. These orders
reflect the FERCs view that it has broad latitude in
determining whether specific behavior violates the rules. In
addition, EPACT 2005 gave the FERC increased penalty authority
for these violations. The FERC may now issue civil penalties of
up to $1 million per day for each violation of FERC rules,
and there are possible criminal penalties of up to
$1 million and 5 years in prison. Given the
FERCs broad mandate granted in EPACT 2005, it is assumed
that if energy prices are high, or exhibit what the FERC deems
to be unusual trading patterns, the FERC will
investigate energy markets to determine if behavior unduly
impacted or manipulated energy prices.
Intrastate
Natural Gas Pipeline Regulation
Intrastate natural gas pipeline operations are not generally
subject to rate regulation by FERC, but they are subject to
regulation by various agencies in the respective states where
they are located. While the regulatory regime varies from state
to state, state agencies typically require intrastate gas
pipelines to file their rates with the agencies and permit
shippers to challenge existing rates or proposed rate increases.
However, to the extent that an intrastate pipeline system
transports natural gas in interstate commerce, the rates, terms
and conditions of such transportation service are subject to
FERC jurisdiction under Section 311 of the Natural Gas
Policy Act, or NGPA. Under Section 311, intrastate
pipelines providing interstate service may avoid jurisdiction
that would otherwise apply under the NGA. Section 311
regulates, among other things, the provision of transportation
services by an intrastate natural gas pipeline on behalf of a
local distribution company or an interstate natural gas
pipeline. Under Section 311, rates charged for
transportation must be fair and equitable, and amounts collected
in excess of fair and equitable rates are subject to refund with
interest. Rates for service pursuant to Section 311 of the
NGPA are generally subject to review and approval by the FERC at
least once every three years. The rate review may, but does not
necessarily, involve an administrative-type hearing before the
FERC staff panel and an administrative appellate review.
Additionally, the terms and conditions of service set forth in
the intrastate pipelines Statement of Operating Conditions
are subject to FERC approval. Failure to observe the service
limitations applicable to transportation services provided under
Section 311, failure to comply with the rates approved by
FERC for Section 311 service, and failure to comply with
the terms and conditions of service established in the
pipelines FERC-approved Statement of Operating Conditions
could result in the assertion of federal NGA jurisdiction by
FERC and/or
the imposition of administrative, civil and criminal penalties.
Among other matters, EPAct 2005 amends the NGPA to give
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FERC authority to impose civil penalties for violations of the
NGPA up to $1,000,000 per day per violation for violations
occurring after August 8, 2005. For violations occurring
before August 8, 2005, FERC had the authority to impose
civil penalties for violations of the NGPA up to $5,000 per
violation per day. The Pelico and EasTrans systems are subject
to FERC jurisdiction under Section 311 of the NGPA.
On December 21, 2007, FERC issued a notice of proposed
rulemaking which proposes to require interstate natural gas
pipelines and certain non-interstate natural gas pipelines to
post capacity, daily scheduled flow information, and daily
actual flow information. On November 20, 2008, FERC issued
Order No. 720, a final rule adopting new regulations that
require certain major non-interstate pipelines and
interstate pipelines to publicly post certain operational and
scheduling information. . Under the final rule, Order
No. 720, major non-interstate gas pipelines
must publicly post on a daily basis on an Internet web site
(1) the design capacity of each receipt or delivery point
that has a design capacity equal to or greater than
15,000 MMBtu/day, and (2) the amount scheduled at each
such delivery point whenever capacity is scheduled. Order
No. 720 defines a major non interstate pipeline
as a company that is not an interstate pipeline and delivers
annually more than fifty million MMBtu of natural gas measured
in average deliveries for the previous three calendar years. The
final rule exempts major non-interstate pipelines that lie
entirely upstream of a processing, treatment, or dehydration
plant. The implementation date is 150 days following the
issuance of an order addressing the pending requests for
rehearing. The Pelico and EastTrans Limited Partnership or East
Trans systems are considered major non interstate pipelines and
are required to comply with this rule. Compliance with this rule
will result in additional administrative burdens related to the
associated information technology costs.
On November 20, 2008, FERC issued an NOI to explore whether
intrastate pipelines and Hinshaw pipelines providing interstate
transportation and storage services should be required to post
details of their transactions with shippers in a manner
comparable to the posting requirements of interstate pipelines.
Comments are due February 13, 2009. FERCs NOI is
subject to change based on comments filed and therefore we
cannot predict the scope of the final rulemaking.
The Discovery interstate natural gas pipeline system filed with
FERC on November 16, 2007 a rate case settlement with a
January 1, 2008 effective date. Also, modifications were
made to the imbalance resolution and fuel reimbursement sections
of Discoverys tariff. The settlement was approved on
February 5, 2008 for all parties except ExxonMobil who
contested the settlement. ExxonMobil will continue to pay the
previous rates. ExxonMobil has an interruptible contract that
was last used in 2006 so there will be no material impact by
this outcome.
Gathering
Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering
facilities from the jurisdiction of FERC under the NGA. We
believe that our natural gas pipelines meet the traditional
tests FERC has used to establish a pipelines status as a
gatherer not subject to FERC jurisdiction. However, the
distinction between FERC-regulated transmission services and
federally unregulated gathering services is the subject of
material, on-going litigation, so the classification and
regulation of our gathering facilities are subject to change
based on future determinations by FERC and the courts. State
regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances,
nondiscriminatory take requirements, and in some instances
complaint-based rate regulation.
Our purchasing, gathering and intrastate transportation
operations are subject to ratable take and common purchaser
statutes in the states in which they operate. The ratable take
statutes generally require gatherers to take, without undue
discrimination, natural gas production that may be tendered to
the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase without undue
discrimination as to source of supply or producer. These
statutes are designed to prohibit discrimination in favor of one
producer over another producer or one source of supply over
another source of supply. These statutes have the effect of
restricting our right as an owner of gathering facilities to
decide with whom we contract to purchase or transport natural
gas.
Natural gas gathering may receive greater regulatory scrutiny at
both the state and federal levels now that FERC has taken a more
light-handed approach to regulation of the gathering activities
of interstate pipeline transmission companies and a number of
such companies have transferred gathering facilities to
unregulated
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affiliates. Many of the producing states have adopted some form
of complaint-based regulation that generally allows natural gas
producers and shippers to file complaints with state regulators
in an effort to resolve grievances relating to natural gas
gathering access and rate discrimination. Our gathering
operations could be adversely affected should they be subject in
the future to the application of state or federal regulation of
rates and services. Additional rules and legislation pertaining
to these matters are considered or adopted from time to time. We
cannot predict what effect, if any, such changes might have on
our operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on
future legislative and regulatory changes.
Sales
of Natural Gas
The price at which we buy and sell natural gas currently is not
subject to federal regulation and, for the most part, is not
subject to state regulation. However, with regard to our
physical purchases and sales of these energy commodities, and
any related derivative activities that we undertake, we are
required to observe anti-market manipulation laws and related
regulations enforced by FERC
and/or the
Commodity Futures Trading Commission, or CFTC. Should we violate
the anti-market manipulation laws and regulations, we could also
be subject to related third party damage claims by, among
others, market participants, sellers, royalty owners and taxing
authorities.
Our sales of natural gas are affected by the availability, terms
and cost of pipeline transportation. As noted above, the price
and terms of access to pipeline transportation are subject to
extensive federal and state regulation. The FERC is continually
proposing and implementing new rules and regulations affecting
those segments of the natural gas industry, most notably
interstate natural gas transmission companies that remain
subject to the FERCs jurisdiction. These initiatives also
may affect the intrastate transportation of natural gas under
certain circumstances. The stated purpose of many of these
regulatory changes is to promote competition among the various
sectors of the natural gas industry. We cannot predict the
ultimate impact of these regulatory changes to our natural gas
marketing operations, and we note that some of the FERCs
more recent proposals may adversely affect the availability and
reliability of interruptible transportation service on
interstate pipelines. We do not believe that we will be affected
by any such FERC action materially differently than other
natural gas marketers with whom we compete.
Interstate
NGL Pipeline Regulation
The Black Lake pipeline is an interstate NGL pipeline subject to
FERC regulation. The FERC regulates interstate NGL pipelines
under its Oil Pipeline Regulations, the Interstate Commerce Act,
or ICA, and the Elkins Act. FERC requires that interstate NGL
pipelines file tariffs containing all the rates, charges and
other terms for services performed. The ICA requires that
tariffs apply to the interstate movement of NGLs, as is the case
with the Black Lake pipeline. Pursuant to the ICA, rates can be
challenged at FERC either by protest when they are initially
filed or increased or by complaint at any time they remain on
file with FERC.
In October 1992, Congress passed the Energy Policy Act of 1992,
or EPAct, which among other things, required the FERC to issue
rules establishing a simplified and generally applicable
ratemaking methodology for pipelines regulated by FERC pursuant
to the ICA. The FERC responded to this mandate by issuing
several orders, including Order No. 561. Beginning
January 1, 1995, Order No. 561 enables petroleum
pipelines to change their rates within prescribed ceiling levels
that are tied to an inflation index. Specifically, the indexing
methodology allows a pipeline to increase its rates annually by
a percentage equal to the change in the producer price index for
finished goods, PPI-FG, plus 1.3% to the new ceiling level. Rate
increases made pursuant to the indexing methodology are subject
to protest, but such protests must show that the portion of the
rate increase resulting from application of the index is
substantially in excess of the pipelines increase in
costs. If the PPI-FG falls and the indexing methodology results
in a reduced ceiling level that is lower than a pipelines
filed rate, Order No. 561 requires the pipeline to reduce
its rate to comply with the lower ceiling unless doing so would
reduce a rate grandfathered by EPAct (see below)
below the grandfathered level. A pipeline must, as a general
rule, utilize the indexing methodology to change its rates. The
FERC, however, retained cost-of-service ratemaking, market based
rates, and settlement as alternatives to the indexing approach,
which alternatives may be used in certain specified
circumstances. The FERCs indexing methodology is subject
to review every five years; the current methodology is expected
to remain in place through
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June 30, 2011. If the FERC continues its policy of using
the PPI-FG plus 1.3%, changes in that index might not fully
reflect actual increases in the costs associated with the
pipelines subject to indexing, thus hampering our ability to
recover cost increases.
EPAct deemed petroleum pipeline rates in effect for the
365-day
period ending on the date of enactment of EPAct that had not
been subject to complaint, protest or investigation during that
365-day
period to be just and reasonable under the ICA. Generally,
complaints against such grandfathered rates may only
be pursued if the complainant can show that a substantial change
has occurred since the enactment of EPAct in either the economic
circumstances of the petroleum pipeline, or in the nature of the
services provided, that were a basis for the rate. EPAct places
no such limit on challenges to a provision of a petroleum
pipeline tariff as unduly discriminatory or preferential.
The pending FERC proceeding regarding the appropriate
composition of proxy groups for purposes of determining equity
returns to be included in cost-of-service based rates is also
applicable to FERC-regulated oil pipelines. On April 17,
2008, FERC issued a final policy statement regarding the
appropriate composition of proxy groups. FERC concluded, among
other things, that MLPs should be included in the ROE proxy
group for both oil and gas pipelines. FERC established a paper
hearing for establishing the ROE for cases that were pending
before FERC. The policy statement could result in the
establishment of a higher ROE in future rate proceedings but the
full effect is uncertain until the policy is applied.
Intrastate
NGL Pipeline Regulation
Intrastate NGL and other petroleum pipelines are not generally
subject to rate regulation by FERC, but they are subject to
regulation by various agencies in the respective states where
they are located. While the regulatory regime varies from state
to state, state agencies typically require intrastate petroleum
pipelines to file their rates with the agencies and permit
shippers to challenge existing rates or proposed rate increases.
Environmental
Matters
General
Our operation of pipelines, plants and other facilities for
gathering, transporting, processing or storing natural gas,
propane, NGLs and other products is subject to stringent and
complex federal, state and local laws and regulations governing
the discharge of materials into the environment or otherwise
relating to the protection of the environment.
As an owner or operator of these facilities, we must comply with
these laws and regulations at the federal, state and local
levels. These laws and regulations can restrict or impact our
business activities in many ways, such as:
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requiring the acquisition of permits to conduct regulated
activities;
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restricting the way we can handle or dispose of our wastes;
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limiting or prohibiting construction activities in sensitive
areas such as wetlands, coastal regions or areas inhabited by
endangered species;
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requiring remedial action to mitigate pollution conditions
caused by our operations or attributable to former
operations; and
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enjoining the operations of facilities deemed in non-compliance
with permits issued pursuant to such environmental laws and
regulations.
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Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of remedial requirements and the issuance of orders
enjoining future operations. Certain environmental statutes
impose strict joint and several liability for costs required to
clean up and restore sites where hazardous substances have been
disposed or otherwise released. Moreover, it is not uncommon for
neighboring landowners and other
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third parties to file claims for personal injury and property
damage allegedly caused by the release of substances or other
waste products into the environment.
The trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment. Thus, there can be no assurance as to the amount or
timing of future expenditures for environmental compliance or
remediation, and actual future expenditures may be different
from the amounts we currently anticipate. We try to anticipate
future regulatory requirements that might be imposed and plan
accordingly to remain in compliance with changing environmental
laws and regulations and to minimize the costs of such
compliance. For instance, we or the entities in which we own an
interest inspect the pipelines regularly using equipment rented
from third party suppliers. Third parties also assist us in
interpreting the results of the inspections. We also actively
participate in industry groups that help formulate
recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local
environmental laws and regulations will have a material adverse
effect on our business, financial position or results of
operations. Below is a discussion of the more significant
environmental laws and regulations that relate to our business
and with which compliance may have a material adverse effect on
our capital expenditures, earnings or competitive position.
Air
Emissions
Our operations are subject to the federal Clean Air Act, as
amended and comparable state laws and regulations. These laws
and regulations regulate emissions of air pollutants from
various industrial sources, including our processing plants and
compressor stations, and also impose various monitoring and
reporting requirements. Such laws and regulations may require
that we obtain pre-approval for the construction or modification
of certain projects or facilities expected to produce or
significantly increase air emissions, obtain and strictly comply
with air permits containing various emissions and operational
limitations, and utilize specific emission control technologies
to limit emissions. Our failure to comply with these
requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. We may be required to
incur certain capital expenditures in the future for air
pollution control equipment in connection with obtaining and
maintaining operating permits and approvals for air emissions.
Following the performance of an audit by us during 2007 on
facilities included in our Northern Louisiana system, we
identified and subsequently self-disclosed to the Louisiana
Department of Environmental Quality alleged violations of
environmental law arising primarily from historical operations
at certain of those facilities. We are currently involved in
settlement discussions with the Louisiana Department of
Environmental Quality to resolve these alleged matters. In
addition, The Colorado Department of Public Health and
Environment, or CDPHE, has alleged violations of the
environmental permit at the Anderson Gulch Gas Plant, as a
result of an inspection in January 2008. The allegations are
primarily related to recordkeeping requirements. We are
currently in settlement discussions with the CDPHE to resolve
this matter. Aside from these enforcement matters, we believe
that we are in material compliance with these requirements. We
do not believe our future operations will be materially
adversely affected by such requirements or enforcement matters.
Hazardous
Substances and Waste
Our operations are subject to environmental laws and regulations
relating to the management and release of hazardous substances
or solid wastes, including petroleum hydrocarbons. These laws
generally regulate the generation, storage, treatment,
transportation and disposal of solid and hazardous waste, and
may impose strict, joint and several liability for the
investigation and remediation of areas at a facility where
hazardous substances may have been released or disposed. For
instance, the Comprehensive Environmental Response,
Compensation, and Liability Act, as amended, or CERCLA, also
known as the Superfund law, and comparable state laws impose
liability, without regard to fault or the legality of the
original conduct, on certain classes of persons that contributed
to the release of a hazardous substance into the
environment. These persons include current and prior owners or
operators of the site where the release occurred and companies
that disposed or arranged for the disposal of the hazardous
substances found at the site. Under CERCLA, these persons may be
subject to joint and several strict liability for the costs of
cleaning up the hazardous substances that have been
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released into the environment, for damages to natural resources
and for the costs of certain health studies. CERCLA also
authorizes the EPA and, in some instances, third parties to act
in response to threats to the public health or the environment
and to seek to recover from the responsible classes of persons
the costs they incur. Despite the petroleum
exclusion of CERCLA Section 101(14) that currently
encompasses natural gas, we may nonetheless handle
hazardous substances within the meaning of CERCLA,
or similar state statutes, in the course of our ordinary
operations and, as a result, may be jointly and severally liable
under CERCLA for all or part of the costs required to clean up
sites at which these hazardous substances have been released
into the environment.
We also generate solid wastes, including hazardous wastes that
are subject to the requirements of the Resource Conservation and
Recovery Act, as amended, or RCRA, and comparable state
statutes. While RCRA regulates both solid and hazardous wastes,
it imposes strict requirements on the generation, storage,
treatment, transportation and disposal of hazardous wastes.
Certain petroleum production wastes are excluded from
RCRAs hazardous waste regulations. However, it is possible
that these wastes, which could include wastes currently
generated during our operations, will in the future be
designated as hazardous wastes and therefore be
subject to more rigorous and costly disposal requirements. Any
such changes in the laws and regulations could have a material
adverse effect on our maintenance capital expenditures and
operating expenses.
We currently own or lease properties where petroleum
hydrocarbons are being or have been handled for many years.
Although we have utilized operating and disposal practices that
were standard in the industry at the time, petroleum
hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by us or on
or under the other locations where these petroleum hydrocarbons
and wastes have been taken for treatment or disposal. In
addition, certain of these properties have been operated by
third parties whose treatment and disposal or release of
petroleum hydrocarbons or other wastes was not under our
control. These properties and wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under these
laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by
prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial
operations to prevent future contamination. We are not currently
aware of any facts, events or conditions relating to such
requirements that could reasonably have a material impact on our
operations or financial condition.
Water
The Federal Water Pollution Control Act of 1972, as amended,
also referred to as the Clean Water Act, or CWA, and analogous
state laws impose restrictions and strict controls regarding the
discharge of pollutants into navigable waters. Pursuant to the
CWA and analogous state laws, permits must be obtained to
discharge pollutants into state and federal waters. The CWA
imposes substantial potential civil and criminal penalties for
non-compliance. State laws for the control of water pollution
also provide varying civil and criminal penalties and
liabilities. In addition, some states maintain groundwater
protection programs that require permits for discharges or
operations that may impact groundwater conditions. The EPA has
promulgated regulations that require us to have permits in order
to discharge certain storm water run-off. The EPA has entered
into agreements with certain states in which we operate whereby
the permits are issued and administered by the respective
states. These permits may require us to monitor and sample the
storm water run-off. We believe that compliance with existing
permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on our financial
condition or results of operations.
Global
Warming and Climate Change
In response to recent studies suggesting that emissions of
carbon dioxide and certain other gases often referred to as
greenhouse gases may be contributing to warming of
the Earths atmosphere, the current session of the
U.S. Congress is considering climate change-related
legislation to regulate greenhouse gas emissions. In addition,
at least one-third of the states have already taken legal
measures to reduce emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission
inventories
and/or
regional greenhouse gas cap and trade programs. Depending on the
particular program, we could be required to purchase and
surrender allowances, either for greenhouse gas emissions
resulting from our operations (e.g.,
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compressor units) or from combustion of fuels (e.g., oil
or natural gas) we process. Also, as a result of the
U.S. Supreme Courts decision on April 2, 2007 in
Massachusetts, et al. v. EPA, the EPA may regulate
carbon dioxide and other greenhouse gas emissions from mobile
sources such as cars and trucks, even if Congress does not adopt
new legislation specifically addressing emissions of greenhouse
gases. The EPA has indicated that it will issue a rulemaking
notice to address carbon dioxide and other greenhouse gas
emissions from vehicles and automobile fuels, although the date
for issuance of this notice has not been finalized. The
Courts holding in the Massachusetts decision that
greenhouse gases including carbon dioxide fall under the federal
Clean Air Acts definition of air pollutant may
also result in future regulation of carbon dioxide and other
greenhouse gas emissions from stationary sources under certain
CAA programs. New federal or state laws requiring adoption of a
stringent greenhouse gas control program or imposing
restrictions on emissions of carbon dioxide in areas of the
United States in which we conduct business could adversely
affect our cost of doing business and demand for the oil and gas
we transport.
Anti-Terrorism
Measures
The federal Department of Homeland Security Appropriations Act
of 2007 requires the Department of Homeland Security, or DHS, to
issue regulations establishing risk-based performance standards
for the security of chemical and industrial facilities, known as
the Chemical Facility Anti-Terrorism Standards interim rule,
including oil and gas facilities that are deemed to present
high levels of security risk. The DHS issued an
interim final rule in April 2007 regarding risk-based
performance standards to be attained pursuant to the act and, on
November 20, 2007, further issued an Appendix A to the
interim rules that established chemicals of interest and their
respective threshold quantities that will trigger compliance
with these interim rules. Facilities possessing greater than
threshold levels of these chemicals of interest were required to
prepare and submit to the DHS in January 2008 initial screening
surveys that the agency would use to determine whether the
facilities presented a high level of security risk. Covered
facilities that are determined by DHS to pose a high level of
security risk will be notified by DHS and will be required to
prepare and submit Security Vulnerability Assessments and Site
Security Plans as well as comply with other regulatory
requirements, including those regarding inspections, audits,
recordkeeping, and protection of chemical-terrorism
vulnerability information. We have not yet determined the extent
to which our facilities are subject to the interim rules or the
associated costs to comply, but it is possible that such costs
could be material.
Employees
Our operations and activities are managed by our general
partner, DCP Midstream GP, LP, which in turn is managed by its
general partner, DCP Midstream GP, LLC, or the General Partner,
which is wholly-owned by DCP Midstream, LLC. As of
December 31, 2008, the General Partner or its affiliates
employed 10 people directly and approximately
138 people who provided direct support for our operations
through DCP Midstream, LLC. None of these employees are covered
by collective bargaining agreements. Our General Partner
considers its employee relations to be good.
General
We make certain filings with the Securities and Exchange
Commission, or SEC, including our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and all amendments and exhibits to those reports, which are
available free of charge through our website,
www.dcppartners.com, as soon as reasonably practicable
after they are filed with the SEC. The filings are also
available through the SEC at the SECs Public Reference
Room at 100 F Street, N.E., Washington, D.C.
20549 or by calling
1-800-SEC-0330.
Also, these filings are available on the internet at
www.sec.gov. Our annual reports to unitholders, press
releases and recent analyst presentations are also available on
our website.
Limited partner interests are inherently different from
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged
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in similar businesses. You should consider carefully the
following risk factors together with all of the other
information included in this annual report in evaluating an
investment in our common units.
If any of the following risks were actually to occur, our
business, financial condition or results of operations could be
materially affected. In that case, we might not be able to pay
the minimum quarterly distribution on our common units, the
trading price of our common units could decline and you could
lose all or part of your investment.
Risks
Related to Our Business
We may
not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to continue to make cash distributions to holders of our
common units at our current distribution rate.
The amount of cash we can distribute on our units principally
depends upon the amount of cash we generate from our operations,
which will fluctuate from quarter to quarter based on, among
other things:
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the fees we charge and the margins we realize for our services;
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the prices of, level of production of, and demand for, natural
gas, propane, condensate and NGLs;
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the success of our commodity derivative and interest rate
hedging programs in mitigating fluctuations in commodity prices
and interest rates;
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the volume of natural gas we gather, treat, compress, process,
transport and sell, the volume of propane and NGLs we transport
and sell, and the volumes of propane we store;
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the relationship between natural gas, NGL and crude oil prices;
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the level of competition from other energy companies;
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the impact of weather conditions on the demand for natural gas
and propane;
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the level of our operating and maintenance and general and
administrative costs; and
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prevailing economic conditions.
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In addition, the actual amount of cash we will have available
for distribution will depend on other factors, some of which are
beyond our control, including:
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the level of capital expenditures we make;
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the cost and form of payment for acquisitions;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets at
reasonable rates;
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restrictions contained in our debt agreements;
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the amount of cash distributions we receive from our equity
interests; and
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the amount of cash reserves established by our general partner.
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We
have partial ownership interests in a number of joint venture
legal entities, including Discovery, East Texas and Black Lake,
which could adversely affect our ability to operate and control
these entities. In addition, we may be unable to control the
amount of cash we will receive from the operation of these
entities and we could be required to contribute significant cash
to fund our share of their operations, which could adversely
affect our ability to distribute cash to you.
Our inability, or limited ability, to control the operations and
management of joint venture legal entities that we have a
partial ownership interest in may mean that we will not receive
the amount of cash we expect to be distributed to us. In
addition, for entities where we have a minority ownership
interest, we will be unable to control ongoing operational
decisions, including the incurrence of capital expenditures that
we may be required to fund. Specifically,
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We have limited ability to influence decisions with respect to
the operations of these entities and their subsidiaries,
including decisions with respect to incurrence of expenses and
distributions to us;
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These entities may establish reserves for working capital,
capital projects, environmental matters and legal proceedings
which would otherwise reduce cash available for distribution to
us;
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These entities may incur additional indebtedness, and principal
and interest made on such indebtedness may reduce cash otherwise
available for distribution to us; and
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These entities may require us to make additional capital
contributions to fund working capital and capital expenditures,
our funding of which could reduce the amount of cash otherwise
available for distribution.
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All of these items could significantly and adversely impact our
ability to distribute cash to the unitholders.
The
amount of cash we have available for distribution to holders of
our common units depends primarily on our cash flow and not
solely on profitability.
Profitability may be significantly affected by non-cash items.
As a result, we may make cash distributions during periods when
we record losses for financial accounting purposes and may not
make cash distributions during periods when we record net
earnings for financial accounting purposes.
Because
of the natural decline in production from existing wells, our
success depends on our ability to obtain new sources of supplies
of natural gas and NGLs.
Our gathering and transportation pipeline systems are connected
to or dependent on the level of production from natural gas
wells, from which production will naturally decline over time.
As a result, our cash flows associated with these wells will
also decline over time. In order to maintain or increase
throughput levels on our gathering and transportation pipeline
systems and NGL pipelines and the asset utilization rates at our
natural gas processing plants, we must continually obtain new
supplies. The primary factors affecting our ability to obtain
new supplies of natural gas and NGLs, and to attract new
customers to our assets include the level of successful drilling
activity near these assets, and our ability to compete for
volumes from successful new wells.
The level of drilling activity is dependent on economic and
business factors beyond our control. The primary factor that
impacts drilling decisions is natural gas prices. Currently,
natural gas prices are lower than in recent periods. For
example, the rolling twelve-month average New York Mercantile
Exchange, or NYMEX, daily settlement price of natural gas
futures contracts per MMBtu was $6.21, $7.96 and $7.23 as of
December 31, 2008, 2007 and 2006 respectively. During
periods of natural gas price decline, the level of drilling
activity could decrease. A sustained decline in natural gas
prices could result in a decrease in exploration and development
activities in the fields served by our gathering and pipeline
transportation systems and our natural gas treating and
processing plants, which would lead to reduced utilization of
these assets. Other factors that impact production decisions
include producers capital budgets, the ability of
producers to borrow funds and access capital markets at
reasonable rates, the ability of producers to obtain necessary
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drilling and other governmental permits, and regulatory changes.
Because of these factors, even if new natural gas reserves are
discovered in areas served by our assets, producers may choose
not to develop those reserves. If we are not able to obtain new
supplies of natural gas to replace the natural decline in
volumes from existing wells, or declines due to reductions in
drilling activity or competition, throughput on our pipelines
and the utilization rates of our treating and processing
facilities would decline, which could have a material adverse
effect on our business, results of operations, financial
position and cash flows.
The
cash flow from our Natural Gas Services segment is affected by
natural gas, NGL and condensate prices.
Our Natural Gas Services segment is affected by the level of
natural gas, NGL and condensate prices. NGL and condensate
prices generally fluctuate on a basis that correlates to
fluctuations in crude oil prices. In the past, the prices of
natural gas and crude oil have been extremely volatile, and we
expect this volatility to continue. The markets and prices for
natural gas, NGLs, condensate and crude oil depend upon factors
beyond our control. These factors include supply of and demand
for these commodities, which fluctuate with changes in market
and economic conditions and other factors, including:
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the impact of weather, including abnormally mild winter or
summer weather that cause lower energy usage for heating or
cooling purposes, respectively, or extreme weather that may
disrupt our operations or related downstream operations;
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the level of domestic and offshore production;
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a general downturn in economic conditions, including demand for
NGLs;
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the availability of imported natural gas, NGLs and crude oil and
the demand in the U.S. and globally for these commodities;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate
transportation systems;
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the availability and marketing of competitive fuels;
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the extent of governmental regulation and taxation.
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Our primary natural gas gathering and processing arrangements
that expose us to commodity price risk are our
percent-of-proceeds arrangements. Under percent-of-proceeds
arrangements, we generally purchase natural gas from producers
for an agreed percentage of the proceeds from the sale of
residue gas and NGLs resulting from our processing activities,
and then sell the resulting residue gas and NGLs at market
prices. Under these types of arrangements, our revenues and our
cash flows increase or decrease, whichever is applicable, as the
price of natural gas and NGLs fluctuate. We have mitigated a
significant portion of our share of anticipated natural gas, NGL
and condensate commodity price risk associated with the equity
volumes from our gathering and processing operations through
2013 with derivative instruments.
Our
derivative activities and the application of fair value
measurements may have a material adverse effect on our earnings,
profitability, cash flows, liquidity and financial
condition.
We are exposed to risks associated with fluctuations in
commodity prices. The extent of our commodity price risk is
related largely to the effectiveness and scope of our derivative
activities. For example, the derivative instruments we utilize
are based on posted market prices, which may differ
significantly from the actual natural gas, NGL and condensate
prices that we realize in our operations. To mitigate our cash
flow exposure to fluctuations in the price of NGLs, we have
primarily entered into derivative financial instruments relating
to the future price of crude oil. If the price relationship
between NGLs and crude oil changes, our commodity price risk may
increase. Furthermore, we have entered into derivative
transactions related to only a portion of the volume of our
expected natural gas supply and production of NGLs and
condensate from our processing plants; as a result, we will
continue to have direct commodity price risk to the open
portion. Our actual future production may be significantly
higher or lower than we estimate at the time we entered into the
derivative transactions for that period. If the actual amount is
higher than we estimate, we will have greater
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commodity price risk than we intended. If the actual amount is
lower than the amount that is subject to our derivative
financial instruments, we might be forced to satisfy all or a
portion of our derivative transactions without the benefit of
the cash flow from our sale of the underlying physical
commodity, reducing our liquidity.
We have mitigated a significant portion of our expected natural
gas, NGL and condensate commodity price risk relating to the
equity volumes from our gathering and processing operations
through 2013 by entering into derivative financial instruments
relating to the future price of natural gas and crude oil.
Additionally, we have entered into interest rate swap agreements
to convert a portion of the variable rate revolving debt under
our 5-year
credit agreement that matures in June 2012, or the Credit
Agreement, to a fixed rate obligation, thereby reducing the
exposure to market rate fluctuations. The intent of these
arrangements is to reduce the volatility in our cash flows
resulting from fluctuations in commodity prices and interest
rates.
We record all of our derivative financial instruments at fair
value on our balance sheets primarily using information readily
observable within the marketplace. In situations where market
observable information is not available, we may use a variety of
data points that are market observable, or in certain instances,
develop our own expectation of fair value. We will continue to
use market observable information as the basis for our fair
value calculations, however, there is no assurance that such
information will continue to be available in the future. In such
instances we may be required to exercise a higher level of
judgment in developing our own expectation of fair value, which
may be significantly different from the historical fair values,
and may increase the volatility of our earnings.
We will continue to evaluate whether to enter into any new
derivative arrangements, but there can be no assurance that we
will enter into any new derivative arrangement or that our
future derivative arrangements will be on terms similar to our
existing derivative arrangements. Although we enter into
derivative instruments to mitigate our commodity price and
interest rate risk, we also forego the benefits we would
otherwise experience if commodity prices or interest rates were
to change in our favor.
The counterparties to our derivative instruments may require us
to post collateral in the event that our potential payment
exposure exceeds a predetermined collateral threshold. Depending
on the movement in commodity prices, the amount of collateral
posted may increase, reducing our liquidity.
As a result of these factors, our derivative activities may not
be as effective as we intend in reducing the volatility of our
cash flows, and in certain circumstances may actually increase
the volatility of our earnings and cash flows. In addition, even
though our management monitors our derivative activities, these
activities can result in material losses. Such losses could
occur under various circumstances, including if a counterparty
does not or is unable to perform its obligations under the
applicable derivative arrangement, the derivative arrangement is
imperfect or ineffective, or our risk management policies and
procedures are not properly followed or do not work as planned.
Volumes
of natural gas dedicated to our systems in the future may be
less than we anticipate.
As a result of the unwillingness of producers to provide reserve
information as well as the cost of such evaluation, we do not
have independent estimates of total reserves dedicated to our
systems or the anticipated life of such reserves. If the
reserves connected to our gathering systems are less than we
anticipate and we are unable to secure additional sources of
natural gas, then the volumes of natural gas on our systems in
the future could be less than we anticipate.
We
depend on certain natural gas producer customers for a
significant portion of our supply of natural gas and
NGLs.
We identify as primary natural gas suppliers those suppliers
individually representing 10% or more of our total natural gas
supply. Our two primary suppliers of natural gas represented
approximately 30% of the natural gas supplied in our Natural Gas
Services segment during the year ended December 31, 2008.
In our NGL Logistics segment, our largest NGL supplier is DCP
Midstream, LLC, who obtains NGLs from various
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third party producer customers. While some of these customers
are subject to long-term contracts, we may be unable to
negotiate extensions or replacements of these contracts on
favorable terms, if at all. The loss of all or even a portion of
the natural gas and NGL volumes supplied by these customers, as
a result of competition or otherwise, could have a material
adverse effect on our business.
If we
are not able to purchase propane from our principal suppliers,
or we are unable to secure transportation under our
transportation arrangements, our results of operations in our
wholesale propane logistics business would be adversely
affected.
Most of our propane purchases are made under supply contracts
that have a term of between one to five years and provide
various pricing formulas. We identify primary suppliers as those
individually representing 10% or more of our total propane
supply. Our three primary suppliers of propane, two of which are
affiliated entities, represented approximately 82% of our
propane supplied during the year ended December 31, 2008.
In the event that we are unable to purchase propane from our
significant suppliers or replace terminated or expired supply
contracts, our failure to obtain alternate sources of supply at
competitive prices and on a timely basis would affect our
ability to satisfy customer demand, reduce our revenues and
adversely affect our results of operations. In addition, if we
are unable to transport propane supply to our terminals under
our rail commitments, our ability to satisfy customer demand and
our revenue and results of operations would be adversely
affected.
We may
not be able to grow or effectively manage our
growth.
A principal focus of our strategy is to continue to grow the per
unit distribution on our units by expanding our business. Our
future growth will depend upon a number of factors, some of
which we can control and some of which we cannot. These factors
include our ability to:
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identify businesses engaged in managing, operating or owning
pipelines, processing and storage assets or other midstream
assets for acquisitions, joint ventures and construction
projects;
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consummate accretive acquisitions or joint ventures and complete
construction projects;
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appropriately identify liabilities associated with acquired
businesses or assets;
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integrate acquired or constructed businesses or assets
successfully with our existing operations and into our operating
and financial systems and controls;
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hire, train and retain qualified personnel to manage and operate
our growing business; and
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obtain required financing for our existing and new operations.
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A deficiency in any of these factors could adversely affect our
ability to achieve growth in the level of our cash flows or
realize benefits from acquisitions, joint ventures or
construction projects. In addition, competition from other
buyers could reduce our acquisition opportunities. In addition,
DCP Midstream, LLC and its affiliates are not restricted from
competing with us. DCP Midstream, LLC and its affiliates may
acquire, construct or dispose of midstream or other assets in
the future without any obligation to offer us the opportunity to
purchase or construct those assets.
Furthermore, we have recently grown significantly through a
number of acquisitions. For example, in May 2007 we acquired the
southern Oklahoma system, in July 2007 we acquired a 25%
interest in East Texas and a 40% interest in Discovery from DCP
Midstream, LLC, in August 2007 we acquired certain subsidiaries
of MEG that hold our Douglas and Collbran assets from DCP
Midstream, LLC and in October 2008, we acquired the Michigan
assets. If we fail to properly integrate these acquired assets
successfully with our existing operations, if the future
performance of these acquired assets does not meet our
expectations, or we did not identify significant liabilities
associated with the acquired assets, the anticipated benefits
from these acquisitions may not be fully realized.
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We may
not successfully balance our purchases and sales of natural gas
and propane.
We purchase from producers and other customers a substantial
amount of the natural gas that flows through our natural gas
gathering, processing and transportation systems for resale to
third parties, including natural gas marketers and end-users. In
addition, in our wholesale propane logistics business, we
purchase propane from a variety of sources and resell the
propane to retail distributors. We may not be successful in
balancing our purchases and sales. A producer or supplier could
fail to deliver contracted volumes or deliver in excess of
contracted volumes, or a purchaser could purchase less than
contracted volumes. Any of these actions could cause our
purchases and sales to be unbalanced. While we attempt to
balance our purchases and sales, if our purchases and sales are
unbalanced, we will face increased exposure to commodity price
risks and could have increased volatility in our operating
income and cash flows.
Our
NGL pipelines could be adversely affected by any decrease in NGL
prices relative to the price of natural gas.
The profitability of our NGL pipelines is dependent on the level
of production of NGLs from processing plants. When natural gas
prices are high relative to NGL prices, it is less profitable to
process natural gas because of the higher value of natural gas
compared to the value of NGLs and because of the increased cost
(principally that of natural gas as a feedstock and fuel) of
separating the NGLs from the natural gas. As a result, we may
experience periods in which higher natural gas prices relative
to NGL prices reduce the volume of natural gas processed at
plants connected to our NGL pipelines, as well as reducing the
amount of NGL extraction, which would reduce the volumes and
gross margins attributable to our NGL pipelines.
Third
party pipelines and other facilities interconnected to our
natural gas and NGL pipelines and facilities may become
unavailable to transport or produce natural gas and
NGLs.
We depend upon third party pipelines and other facilities that
provide delivery options to and from our pipelines and
facilities for the benefit of our customers. Since we do not own
or operate any of these third-party pipelines or other
facilities, their continuing operation is not within our control.
Service
at our propane terminals may be interrupted.
Historically, a substantial portion of the propane we purchase
to support our wholesale propane logistics business is delivered
at our rail terminals or by ship at our leased marine terminal
in Providence, Rhode Island. We also rely on shipments of
propane via the Buckeye Pipeline for our Midland Terminal and
via TEPPCO Partners, LPs pipeline to open access
terminals. Any significant interruption in the service at these
terminals would adversely affect our ability to obtain propane,
which could reduce the amount of propane that we distribute and
impact our revenues or cash available for distribution.
We
operate in a highly competitive business
environment.
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial
resources and access to supplies of natural gas, propane and
NGLs than we do. Some of these competitors may expand or
construct gathering, processing and transportation systems that
would create additional competition for the services we provide
to our customers. Likewise, our customers who produce NGLs may
develop their own systems to transport NGLs. Additionally, our
wholesale propane distribution customers may develop their own
sources of propane supply. Our ability to renew or replace
existing contracts with our customers at rates sufficient to
maintain current revenues and cash flows could be adversely
affected by the activities of our competitors and our customers.
Weather
conditions, such as warm winters, principally in the
northeastern United States, may affect the overall demand for
propane.
Weather conditions could have an impact on the demand for
wholesale propane because the end-users of propane depend on
propane principally for heating purposes. As a result, warm
weather conditions could
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adversely impact the demand for and prices of propane. Since our
wholesale propane logistics business is located almost solely in
the northeast, warmer than normal temperatures in the northeast
can decrease the total volume of propane we sell. Such
conditions may also cause downward pressure on the price of
propane, which could result in a lower of cost or market
adjustment to the value of our inventory.
Competition
from alternative energy sources, conservation efforts and energy
efficiency and technological advances may reduce the demand for
propane.
Competition from alternative energy sources, including natural
gas and electricity, has been increasing as a result of reduced
regulation of many utilities. In addition, propane competes with
heating oil primarily in residential applications. Propane is
generally not competitive with natural gas in areas where
natural gas pipelines already exist because natural gas is a
less expensive source of energy than propane. The gradual
expansion of natural gas distribution systems and availability
of natural gas in the northeast, which has historically depended
upon propane, could reduce the demand for propane, which could
adversely affect the volumes of propane that we distribute. In
addition, stricter conservation measures in the future or
technological advances in heating, energy generation or other
devices could reduce the demand for propane.
A
change in the jurisdictional characterization of some of our
assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased
regulation of our assets.
The majority of our natural gas gathering and intrastate
transportation operations are exempt from FERC regulation under
the NGA but FERC regulation still affects these businesses and
the markets for products derived from these businesses.
FERCs policies and practices across the range of its oil
and natural gas regulatory activities, including, for example,
its policies on open access transportation, ratemaking, capacity
release and market center promotion, indirectly affect
intrastate markets. In recent years, FERC has pursued
pro-competitive policies in its regulation of interstate oil and
natural gas pipelines. However, we cannot assure that FERC will
continue this approach as it considers matters such as pipeline
rates and rules and policies that may affect rights of access to
oil and natural gas transportation capacity. In addition, the
distinction between FERC-regulated transmission services and
federally unregulated gathering services has been the subject of
regular litigation, so the classification and regulation of some
of our gathering facilities and intrastate transportation
pipelines may be subject to change based on any reassessment by
us of the jurisdictional status of our facilities or on future
determinations by FERC and the courts.
In addition, the rates, terms and conditions of some of the
transportation services we provide on our Pelico pipeline system
and the EasTrans Limited Partnership or EasTrans pipeline system
owned by East Texas, are subject to FERC regulation under
Section 311 of the NGPA. Under Section 311, rates
charged for transportation must be fair and equitable, and
amounts collected in excess of fair and equitable rates are
subject to refund with interest. The Pelico system is currently
charging rates for its Section 311 transportation services
that were deemed fair and equitable under a rate settlement with
FERC. The EasTrans system is currently charging rates for its
Section 311 transportation services that were deemed fair
and equitable under an order approved by the Railroad Commission
of Texas. The Black Lake pipeline system is an interstate
transporter of NGLs and is subject to FERC jurisdiction under
the Interstate Commerce Act and the Elkins Act.
Should we fail to comply with all applicable FERC-administered
statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines. Under EPAct 2005, FERC has
civil penalty authority under the NGA and the NGPA to impose
penalties for current violations of up to $1,000,000 per day for
each violation.
Other state and local regulations also affect our business. Our
non-proprietary gathering lines are subject to ratable take and
common purchaser statutes in Louisiana. Ratable take statutes
generally require gatherers to take, without undue
discrimination, oil or natural gas production that may be
tendered to the gatherer for handling. Similarly, common
purchaser statutes generally require gatherers to purchase
without undue discrimination as to source of supply or producer.
These statutes restrict our right as an owner of gathering
facilities to decide with whom we contract to purchase or
transport oil or natural gas. Federal law leaves any
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economic regulation of natural gas gathering to the states. The
states in which we operate have adopted complaint-based
regulation of oil and natural gas gathering activities, which
allows oil and natural gas producers and shippers to file
complaints with state regulators in an effort to resolve
grievances relating to oil and natural gas gathering access and
rate discrimination. Other state regulations may not directly
regulate our business, but may nonetheless affect the
availability of natural gas for purchase, processing and sale,
including state regulation of production rates and maximum daily
production allowable from gas wells. While our proprietary
gathering lines are currently subject to limited state
regulation, there is a risk that state laws will be changed,
which may give producers a stronger basis to challenge
proprietary status of a line, or the rates, terms and conditions
of a gathering line providing transportation service.
Discoverys
interstate tariff rates are subject to review and possible
adjustment by federal regulators. Moreover, because Discovery is
a non-corporate entity, it may be disadvantaged in calculating
its cost-of-service for rate-making purposes.
The FERC, pursuant to the NGA, regulates many aspects of
Discoverys interstate pipeline transportation service,
including the rates that Discovery is permitted to charge for
such service. Under the NGA, interstate transportation rates
must be just and reasonable and not unduly discriminatory. If
the FERC fails to permit tariff rate increases requested by
Discovery, or if the FERC lowers the tariff rates Discovery is
permitted to charge its customers, on its own initiative, or as
a result of challenges raised by Discoverys customers or
third parties, Discoverys tariff rates may be insufficient
to recover the full cost of providing interstate transportation
service. In certain circumstances, the FERC also has the power
to order refunds.
The Discovery interstate natural gas pipeline system filed with
FERC on November 16, 2007 a rate case settlement with a
January 1, 2008 effective date. Also, modifications were
made to the imbalance resolution and fuel reimbursement sections
of Discoverys tariff. FERC approved the settlement on
February 5, 2008 for all parties except ExxonMobil who
contested the settlement. ExxonMobil will continue to pay the
previous rates.
Under current policy, the FERC permits pipelines to include, in
the cost-of-service used as the basis for calculating the
pipelines regulated rates, a tax allowance reflecting the
actual or potential income tax liability on public utility
income attributable to all partnership or limited liability
company interests, if the ultimate owner of the interest has an
actual or potential income tax liability on such income. Whether
a pipelines owners have such actual or potential income
tax liability will be reviewed by the FERC on a
case-by-case
basis. In a future rate case, Discovery may be required to
demonstrate the extent to which inclusion of an income tax
allowance in Discoverys cost-of-service is permitted under
the current income tax allowance policy.
Should we fail to comply with all applicable FERC-administered
statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines. Under EPAct 2005 FERC has civil
penalty authority under the NGA to impose penalties for current
violations of up to $1,000,000 per day for each violation.
We may
incur significant costs and liabilities in the future resulting
from a failure to comply with new or existing environmental
regulations or an accidental release of hazardous substances or
hydrocarbons into the environment.
Our operations are subject to stringent and complex federal,
state and local environmental laws and regulations. These
include, for example, (1) the federal Clean Air Act and
comparable state laws and regulations that impose obligations
related to air emissions; (2) the federal Resource
Conservation and Recovery Act, or RCRA, and comparable state
laws that impose requirements for the discharge of waste from
our facilities; and (3) the Comprehensive Environmental
Response Compensation and Liability Act of 1980, or CERCLA, also
known as Superfund, and comparable state laws that
regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated
by us or locations to which we have sent waste for disposal.
Failure to comply with these laws and regulations or newly
adopted laws or regulations may trigger a variety of
administrative, civil and criminal enforcement measures,
including the assessment of monetary penalties, the imposition
of remedial requirements, and the
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issuance of orders enjoining future operations. Certain
environmental regulations, including CERCLA and analogous state
laws and regulations, impose strict, joint and several liability
for costs required to clean up and restore sites where hazardous
substances or hydrocarbons have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances, hydrocarbons or other waste products into
the environment.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to our handling of natural
gas, NGLs and other petroleum products, air emissions related to
our operations, and historical industry operations and waste
disposal practices. For example, an accidental release from one
of our facilities could subject us to substantial liabilities
arising from environmental cleanup and restoration costs, claims
made by neighboring landowners and other third parties for
personal injury and property damage and governmental claims for
natural resource damages or fines or penalties for related
violations of environmental laws or regulations. In addition, it
is possible that stricter laws, regulations or enforcement
policies could significantly increase our compliance costs and
the cost of any remediation that may become necessary. We may
not be able to recover some or any of these costs from insurance
or from indemnification from DCP Midstream, LLC.
We may
incur significant costs and liabilities resulting from
implementing and administering pipeline integrity programs and
related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT
has adopted regulations requiring pipeline operators to develop
integrity management programs for transportation pipelines
located where a leak or rupture could do the most harm in
high consequence areas. The regulations require
operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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Although many of our natural gas facilities fall within a class
that is not subject to these requirements, we may incur
significant costs and liabilities associated with repair,
remediation, preventative or mitigation measures associated with
non-exempt pipeline. Such costs and liabilities might relate to
repair, remediation, preventative or mitigating actions that may
be determined to be necessary as a result of the testing
program, as well as lost cash flows resulting from shutting down
our pipelines during the pendency of such repairs. Additionally,
we may be affected by the testing, maintenance and repair of
pipeline facilities downstream from our own facilities. Our NGL
pipelines are also subject to integrity management and other
safety regulations imposed by the Texas Railroad Commission, or
TRRC.
We currently estimate that we will incur costs of approximately
$2.0 million between 2009 and 2013 to implement pipeline
integrity management program testing along certain segments of
our natural gas and NGL pipelines. This does not include the
costs, if any, of any repair, remediation, preventative or
mitigating actions that may be determined to be necessary as a
result of the testing program, which costs could be substantial.
We currently transport all of the NGLs produced at our Minden
plant on the Black Lake pipeline. Accordingly, in the event that
the Black Lake pipeline becomes inoperable due to any necessary
repairs resulting from our integrity testing program or for any
other reason for any significant period of time, we would need
to transport NGLs by other means. The Minden plant has an
existing alternate pipeline connection that would permit the
transportation of NGLs to a local fractionator for processing
and distribution with sufficient pipeline takeaway and
fractionation capacity to handle all of the Minden plants
NGL production. We do not, however, currently have commercial
arrangements in place with the alternative pipeline. While we
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believe we could establish alternate transportation
arrangements, there can be no assurance that we will in fact be
able to enter into such arrangements.
Any regulatory expansion of the existing pipeline safety
requirements or the adoption of new pipeline safety requirements
could also increase our cost of operation and impair our ability
to provide service during the period in which assessments and
repairs take place, adversely affecting our business.
Construction
of new assets is subject to regulatory, environmental,
political, legal, economic and other risks that may adversely
affect financial results.
The construction of additions or modifications to our existing
midstream asset systems or propane terminals involves numerous
regulatory, environmental, political and legal and economic
uncertainties beyond our control and may require the expenditure
of significant amounts of capital. These projects may not be
completed on schedule or within budgeted cost, or at all. We may
construct facilities to capture anticipated future growth in
production in a region in which such growth does not
materialize. Since we are not engaged in the exploration for and
development of natural gas and oil reserves, we often do not
have access to third party estimates of potential reserves in an
area prior to constructing facilities in such area. To the
extent we rely on estimates of future production in our decision
to construct additions to our systems, such estimates may prove
to be inaccurate because there are numerous uncertainties
inherent in estimating quantities of future production. As a
result, new facilities may not be able to attract enough
throughput to achieve our expected investment return, which
could adversely affect our results of operations and financial
condition. The construction of additions to our existing
gathering, transportation and propane terminal assets may
require us to obtain new rights-of-way prior to constructing new
facilities. We may be unable to obtain such rights-of-way to
connect new natural gas supplies to our existing gathering
lines, expand our network of propane terminals, or capitalize on
other attractive expansion opportunities. The construction of
additions to our existing gathering, transportation and propane
terminal assets may require us to rely on third parties
downstream of our facilities to have available capacity for our
delivered natural gas, natural gas liquids, or propane. If such
third party facilities are not constructed or operational at the
time that the addition to our facilities is completed, we may
experience adverse effects on our results of operations and
financial condition. The construction of additional propane
terminals may require greater capital investment if the
commodity prices of certain supplies such as steel increase.
Construction also subjects us to risks related to the ability to
construct projects within anticipated costs, including the risk
of cost overruns resulting from inflation or increased costs of
equipment, materials, labor, or other factors beyond our control
that could adversely affect results of operations, financial
position or cash flows.
If we
do not make acquisitions on economically acceptable terms, our
future growth will be limited.
Our acquisition strategy is based, in part, on our expectation
of ongoing divestitures of energy assets by industry
participants. Our ability to make acquisitions that are
accretive to our cash generated from operations per unit is
based upon our ability to identify attractive acquisition
candidates or negotiate acceptable purchase contracts with them
and obtain financing for these acquisitions on economically
acceptable terms. Furthermore, even if we do make acquisitions
that we believe will be accretive, these acquisitions may
nevertheless result in a decrease in the cash generated from
operations per unit. Additionally, net assets contributed by DCP
Midstream, LLC represent a transfer of net assets between
entities under common control, and are recognized at DCP
Midstream, LLCs basis in the net assets transferred. The
amount of the purchase price in excess of DCP Midstream,
LLCs basis in the net assets, if any, is recognized as a
reduction to partners equity. Contributions from DCP
Midstream, LLC may significantly increase our debt to
capitalization ratios.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, future contract terms with
customers, revenues and costs, including synergies;
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an inability to successfully integrate the businesses we acquire;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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change in competitive landscape;
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unforeseen difficulties operating in new product areas or new
geographic areas; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and unitholders
will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider
in determining the application of these funds and other
resources.
In addition, any limitations on our access to substantial new
capital to finance strategic acquisitions will impair our
ability to execute this component of our growth strategy. If the
cost of such capital becomes too expensive, our ability to
develop or acquire accretive assets will be limited. We may not
be able to raise the necessary funds on satisfactory terms, if
at all. The primary factors that influence our cost of capital
include market conditions and offering or borrowing costs such
as interest rates or underwriting discounts.
We do
not own all of the land on which our pipelines, facilities and
rail terminals are located.
Upon contract lease renewal, we may be subject to more onerous
terms and/or
increased costs to retain necessary land use if we do not have
valid rights of way or if such rights of way lapse or terminate.
We obtain the rights to construct and operate our pipelines,
surface sites and rail terminals on land owned by third parties
and governmental agencies for a specific period of time.
Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance.
Our operations are subject to many hazards inherent in the
gathering, compressing, treating, processing and transporting of
natural gas, propane and NGLs, and the storage of propane,
including:
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damage to pipelines, plants and terminals, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of natural gas, propane, NGLs and other hydrocarbons or
losses of natural gas, propane or NGLs as a result of the
malfunction of equipment or facilities;
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contaminants in the pipeline system;
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fires and explosions; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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These risks could result in substantial losses due to personal
injury
and/or loss
of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage and may
result in curtailment or suspension of our related operations.
We are not fully insured against all risks inherent to our
business. In accordance with typical industry practice, we do
not have any property insurance on any of our underground
pipeline systems that would cover damage to the pipelines. We
are not insured against all environmental accidents that might
occur, which may include toxic tort claims, other than those
considered to be sudden and accidental. In some instances,
certain insurance could become unavailable or available only for
reduced amounts of coverage, or may become prohibitively
expensive, and we may elect not to carry policy.
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Recent
turmoil in the capital markets may adversely impact our
liquidity.
The capital markets have recently experienced volatility,
uncertainty and interventions by various governments around the
globe. This turmoil in the global capital markets has caused
significant financial uncertainty. Our access to funds under the
Credit Agreement is dependent on the ability of the lenders that
are party to the Credit Agreement to meet their funding
obligations. Those lenders may not be able to meet their funding
commitments if they experience shortages of capital and
liquidity. Lehman Brothers Commercial Bank, or Lehman Brothers,
a lender to the Credit Agreement, has failed to fund under that
agreement since its bankruptcy. Accordingly, the capacity under
our Credit Agreement is approximately $824.6 million,
excluding Lehman Brothers unfunded commitment. If
additional lenders under the Credit Agreement were to fail to
fund their share of the Credit Agreement, our available
borrowings could be further reduced. In addition, our borrowing
capacity may be further limited by the Credit Agreements
financial covenant requirements.
A significant downturn in the economy could adversely affect our
results of operations, financial position or cash flows. In the
event that our results were negatively impacted, we could
require additional funds for working capital purposes. The
recent turmoil in the capital markets has resulted in
significantly higher costs of public debt and equity funds and
reduced funding capabilities generally. Further deterioration in
the capital markets could adversely affect our ability to access
funds on reasonable terms in a timely manner.
Our
debt levels may limit our flexibility in obtaining additional
financing and in pursuing other business
opportunities.
Our Credit Agreement has capacity of approximately
$824.6 million, assuming no capacity related to Lehman
Brothers unfunded commitment, matures on June 21,
2012, and consists of a $764.6 million revolving credit
facility and a $60.0 million term loan facility for working
capital and other general corporate purposes. As of
December 31, 2008, the outstanding balance on the revolving
credit facility was $596.5 million and the outstanding
balance on the term loan facility was $60.0 million.
We continue to have the ability to incur additional debt,
subject to limitations within our credit facility. Our level of
debt could have important consequences to us, including the
following:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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an increased amount of cash flow will be required to make
interest payments on our debt;
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our debt level will make us more vulnerable to competitive
pressures or a downturn in our business or the economy
generally; and
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our debt level may limit our flexibility in responding to
changing business and economic conditions.
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Our ability to obtain new debt funding or service our existing
debt will depend upon, among other things, our future financial
and operating performance, which will be affected by prevailing
economic conditions and financial, business, regulatory and
other factors. In addition, our ability to service debt under
our revolving credit facility will depend on market interest
rates. If our operating results are not sufficient to service
our current or future indebtedness, we may take actions such as
reducing distributions, reducing or delaying our business
activities, acquisitions, investments or capital expenditures,
selling assets, restructuring or refinancing our debt, or
seeking additional equity capital. We may not be able to effect
any of these actions on satisfactory terms, or at all.
Restrictions
in our credit facility may limit our ability to make
distributions to unitholders and may limit our ability to
capitalize on acquisitions and other business
opportunities.
Our credit facility contains covenants limiting our ability to
make distributions, incur indebtedness, grant liens, make
acquisitions, investments or dispositions and engage in
transactions with affiliates. Furthermore, our credit facility
contains covenants requiring us to maintain certain financial
ratios and tests. Any subsequent replacement of our credit
facility or any new indebtedness could have similar or greater
restrictions.
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Changes
in interest rates may adversely impact our ability to issue
additional equity or incur debt, as well as the ability of
exploration and production companies to finance new drilling
programs around our systems.
Interest rates on future credit facilities and debt offerings
could be higher than current levels, causing our financing costs
to increase. As with other yield-oriented securities, our unit
price is impacted by the level of our cash distributions and
implied distribution yield. The distribution yield is often used
by investors to compare and rank related yield-oriented
securities for investment decision-making purposes. Therefore,
changes in interest rates, either positive or negative, may
affect the yield requirements of investors who invest in our
units, and a rising interest rate environment could impair our
ability to issue additional equity to make acquisitions, or
incur debt or for other purposes. Increased interest costs could
also inhibit the financing of new capital drilling programs by
exploration and production companies served by our systems.
Due to
our lack of industry diversification, adverse developments in
our midstream operations or operating areas would reduce our
ability to make distributions to our unitholders.
We rely on the cash flow generated from our midstream energy
businesses, and as a result, our financial condition depends
upon prices of, and continued demand for, natural gas, propane,
condensate and NGLs. Due to our lack of diversification in
industry type, an adverse development in one of these businesses
may have a significant impact on our company.
We are
exposed to the credit risks of our key producer customers and
propane purchasers, and any material nonpayment or
nonperformance by our key producer customers or our propane
purchasers could reduce our ability to make distributions to our
unitholders.
We are subject to risks of loss resulting from nonpayment or
nonperformance by our producer customers and propane purchasers.
Any material nonpayment or nonperformance by our key producer
customers or our propane purchasers could reduce our ability to
make distributions to our unitholders. Furthermore, some of our
producer customers or our propane purchasers may be highly
leveraged and subject to their own operating and regulatory
risks, which could increase the risk that they may default on
their obligations to us.
Terrorist
attacks, the threat of terrorist attacks, and sustained military
campaigns may adversely impact our results of
operations.
The long-term impact of terrorist attacks, such as the attacks
that occurred on September 11, 2001 or the attacks in
London, and the threat of future terrorist attacks on our
industry in general, and on us in particular, is not known at
this time. Increased security measures taken by us as a
precaution against possible terrorist attacks have resulted in
increased costs to our business. Uncertainty surrounding
continued hostilities in the Middle East or other sustained
military campaigns may affect our operations in unpredictable
ways, including disruptions of crude oil supplies, propane
shipments or storage facilities, and markets for refined
products, and the possibility that infrastructure facilities
could be direct targets of, or indirect casualties of, an act of
terror.
Risks
Inherent in an Investment in Our Common Units
Conflicts
of interest may exist between individual unitholders and DCP
Midstream, LLC, our general partner, which has sole
responsibility for conducting our business and managing our
operations.
DCP Midstream, LLC owns and controls our general partner. Some
of our general partners directors, and some of its
executive officers, are directors or officers of DCP Midstream,
LLC or its parents. Therefore, conflicts of interest may arise
between DCP Midstream, LLC and its affiliates and our
unitholders. In resolving these conflicts of interest, our
general partner may favor its own interests and the interests of
its affiliates over the interests of our unitholders. These
conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement
requires DCP Midstream, LLC to pursue a business strategy that
favors us. DCP Midstream, LLCs directors and officers have
a fiduciary duty to
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make these decisions in the best interests of the owners of DCP
Midstream, LLC, which may be contrary to our interests;
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our general partner is allowed to take into account the
interests of parties other than us, such as DCP Midstream, LLC
and its affiliates, in resolving conflicts of interest;
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DCP Midstream, LLC and its affiliates, including Spectra Energy
and ConocoPhillips, are not limited in their ability to compete
with us. Please read DCP Midstream, LLC and its affiliates
are not limited in their ability to compete with us below;
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once certain requirements are met, our general partner may make
a determination to receive a quantity of our Class B units
in exchange for resetting the target distribution levels related
to its incentive distribution rights without the approval of the
special committee of our general partner or our unitholders;
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some officers of DCP Midstream, LLC who provide services to us
also will devote significant time to the business of DCP
Midstream, LLC, and will be compensated by DCP Midstream, LLC
for the services rendered to it;
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our general partner has limited its liability and reduced its
fiduciary duties, and has also restricted the remedies available
to our unitholders for actions that, without the limitations,
might constitute breaches of fiduciary duty;
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our general partner determines the amount and timing of asset
purchases and sales, borrowings, issuance of additional
partnership securities and reserves, each of which can affect
the amount of cash that is distributed to unitholders;
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our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is a
maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not
reduce operating surplus. This determination can affect the
amount of cash that is distributed to our unitholders;
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our general partner determines which costs incurred by it and
its affiliates are reimbursable by us;
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our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our
contractual and other obligations and, in some circumstances, is
entitled to be indemnified by us;
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our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than 80%
of the common units;
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our general partner controls the enforcement of obligations owed
to us by our general partner and its affiliates; and
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our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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DCP
Midstream, LLC and its affiliates are not limited in their
ability to compete with us, which could cause conflicts of
interest and limit our ability to acquire additional assets or
businesses, which in turn could adversely affect our results of
operations and cash available for distribution to our
unitholders.
Neither our partnership agreement nor the Omnibus Agreement, as
amended, between us, DCP Midstream, LLC and others will prohibit
DCP Midstream, LLC and its affiliates, including ConocoPhillips,
Spectra Energy and Spectra Energy Partners, LP, from owning
assets or engaging in businesses that compete directly or
indirectly with us. In addition, DCP Midstream, LLC and its
affiliates, including Spectra Energy and ConocoPhillips, may
acquire, construct or dispose of additional midstream or other
assets in the future, without any obligation to offer us the
opportunity to purchase or construct any of those assets. Each
of these
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entities is a large, established participant in the midstream
energy business, and each has significantly greater resources
and experience than we have, which factors may make it more
difficult for us to compete with these entities with respect to
commercial activities as well as for acquisition candidates. As
a result, competition from these entities could adversely impact
our results of operations and cash available for distribution.
Cost
reimbursements due to our general partner and its affiliates for
services provided, which will be determined by our general
partner, will be material.
Pursuant to the Omnibus Agreement, as amended, we entered into
with DCP Midstream, LLC, our general partner and others, DCP
Midstream, LLC will receive reimbursement for the payment of
operating expenses related to our operations and for the
provision of various general and administrative services for our
benefit. Payments for these services will be material. In
addition, under Delaware partnership law, our general partner
has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual
obligations that are expressly made without recourse to our
general partner. To the extent our general partner incurs
obligations on our behalf, we are obligated to reimburse or
indemnify it. If we are unable or unwilling to reimburse or
indemnify our general partner, our general partner may take
actions to cause us to make payments of these obligations and
liabilities. These factors may reduce the amount of cash
otherwise available for distribution to our unitholders.
Our
partnership agreement limits our general partners
fiduciary duties to holders of our common units.
Although our general partner has a fiduciary duty to manage us
in a manner beneficial to us and our unitholders, the directors
and officers of our general partner have a fiduciary duty to
manage our general partner in a manner beneficial to its owner,
DCP Midstream, LLC. Our partnership agreement contains
provisions that reduce the standards to which our general
partner would otherwise be held by state fiduciary duty laws.
For example, our partnership agreement permits our general
partner to make a number of decisions either in its individual
capacity, as opposed to in its capacity as our general partner
or otherwise free of fiduciary duties to us and our unitholders.
This entitles our general partner to consider only the interests
and factors that it desires, and it has no duty or obligation to
give any consideration to any interest of, or factors affecting,
us, our affiliates or any limited partner. Examples include:
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the exercise of its right to reset the target distribution
levels of its incentive distribution rights at higher levels and
receive, in connection with this reset, a number of Class B
units that are convertible at any time following the first
anniversary of the issuance of these Class B units into
common units;
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its limited call right;
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its voting rights with respect to the units it owns;
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its registration rights; and
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its determination whether or not to consent to any merger or
consolidation of the partnership or amendment to the partnership
agreement.
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By purchasing a common unit, a common unitholder will agree to
become bound by the provisions in the partnership agreement,
including the provisions discussed above.
Our
partnership agreement restricts the remedies available to
holders of our common units for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that restrict the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty. For example, our partnership agreement:
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the special committee
of the board of directors of our general partner and not
involving a vote of unitholders must be on terms no less
favorable to us than those generally being provided to or
available from unrelated third parties or must be fair and
reasonable to us, as determined by our general partner in
good faith and that, in determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us; and provides that
our general partner and its officers and directors will not be
liable for monetary damages to us, our limited partners or
assignees for any acts or omissions unless there has been a
final and non-appealable judgment entered by a court of
competent jurisdiction determining that the general partner or
those other persons acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal.
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Our
general partner may elect to cause us to issue Class B
units to it in connection with a resetting of the target
distribution levels related to our general partners
incentive distribution rights without the approval of the
special committee of our general partner or holders of our
common units. This may result in lower distributions to holders
of our common units in certain situations.
Our general partner has the right, at a time it has received
incentive distributions at the highest level to which it is
entitled (48%) for each of the prior four consecutive fiscal
quarters, to reset the initial cash target distribution levels
at higher levels based on the distribution at the time of the
exercise of the reset election. Following a reset election by
our general partner, the minimum quarterly distribution amount
will be reset to an amount equal to the average cash
distribution amount per common unit for the two fiscal quarters
immediately preceding the reset election (such amount is
referred to as the reset minimum quarterly
distribution) and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution amount.
Currently, our distribution to our general partner related to
its incentive distribution rights is at the highest level.
In connection with resetting these target distribution levels,
our general partner will be entitled to receive a number of
Class B units. The Class B units will be entitled to
the same cash distributions per unit as our common units and
will be convertible into an equal number of common units. The
number of Class B units to be issued will be equal to that
number of common units whose aggregate quarterly cash
distributions equaled the average of the distributions to our
general partner on the incentive distribution rights in the
prior two quarters. We anticipate that our general partner would
exercise this reset right in order to facilitate acquisitions or
internal growth projects that would not be sufficiently
accretive to cash distributions per common unit without such
conversion; however, it is possible that our general partner
could exercise this reset election at a time when it is
experiencing, or may be expected to experience, declines in the
cash distributions it receives related to its incentive
distribution rights and may therefore desire to be issued our
Class B units, which are entitled to receive cash
distributions from us on the same priority as our common units,
rather than retain the right to receive incentive distributions
based on the initial target distribution levels. As a result, in
certain situations, a reset election may cause our common
unitholders to experience dilution in the amount of cash
distributions that they would have otherwise received had we not
issued new Class B units to our general partner in
connection with resetting the target distribution levels related
to our general partner incentive distribution rights.
Holders
of our common units have limited voting rights and are not
entitled to elect our general partner or its
directors.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will not elect our general partner or its board of directors,
and will have no right to elect our general partner or its board
of directors on an annual or other continuing basis. The board
of directors of our general partner will be chosen by the
members of our general partner. As a result of these
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limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Even
if holders of our common units are dissatisfied, they may be
unable to remove our general partner without its
consent.
The unitholders may be unable to remove our general partner
without its consent because our general partner and its
affiliates own sufficient units to be able to prevent its
removal. The vote of the holders of at least
662/3%
of all outstanding units voting together as a single class is
required to remove the general partner. As of December 31,
2008, our general partner and its affiliates owned approximately
30% of our aggregate outstanding common units.
Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
Unitholders voting rights are further restricted by the
partnership agreement provision providing that any units held by
a person that owns 20% or more of any class of units then
outstanding, other than our general partner, its affiliates,
their transferees and persons who acquired such units with the
prior approval of the board of directors of our general partner,
cannot vote on any matter. Our partnership agreement also
contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well
as other provisions limiting the unitholders ability to
influence the manner or direction of management.
If we
are deemed an investment company under the
Investment Company Act of 1940, it would adversely affect the
price of our common units and could have a material adverse
effect on our business.
Our current assets include a 25% interest in East Texas, a 40%
interest in Discovery, a 45% interest in Black Lake and
investments in certain commercial paper and other high grade
debt securities, some or all of which may be deemed to be
investment securities within the meaning of the
Investment Company Act of 1940. If a sufficient amount of our
assets are deemed to be investment securities within
the meaning of the Investment Company Act, we would either have
to register as an investment company under the Investment
Company Act, obtain exemptive relief from the Commission or
modify our organizational structure or our contract rights to
fall outside the definition of an investment company.
Registering as an investment company could, among other things,
materially limit our ability to engage in transactions with
affiliates, including the purchase and sale of certain
securities or other property to or from our affiliates, restrict
our ability to borrow funds or engage in other transactions
involving leverage and require us to add additional directors
who are independent of us or our affiliates. The occurrence of
some or all of these events may have a material adverse effect
on our business.
Moreover, treatment of us as an investment company would prevent
our qualification as a partnership for federal income tax
purposes in which case we would be treated as a corporation for
federal income tax purposes, and be subject to federal income
tax at the corporate tax rate, significantly reducing the cash
available for distributions. Additionally, distributions to the
unitholders would be taxed again as corporate distributions and
none of our income, gains, losses or deductions would flow
through to the unitholders.
Additionally, as a result of our desire to avoid having to
register as an investment company under the Investment Company
Act, we may have to forego potential future acquisitions of
interests in companies that may be deemed to be investment
securities within the meaning of the Investment Company Act or
dispose of our current interests in East Texas, Discovery or
Black Lake.
Control
of our general partner may be transferred to a third party
without unitholder consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of the owners of our general partner from transferring
all or a portion of their respective ownership interest in our
general partner to a third party. The new owners of our general
partner
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would then be in a position to replace the board of directors
and officers of the general partner with its own choices and
thereby influence the decisions taken by the board of directors
and officers.
We may
issue additional units without your approval, which would dilute
your existing ownership interests.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. The issuance by us
of additional common units or other equity securities of equal
or senior rank will have the following effects:
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your proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Certain
of our investors, including affiliates of our general partner,
may sell units in the public or private markets, which could
reduce the market price of our outstanding common
units.
Pursuant to agreements with investors in private placements
effected in 2007, we have filed a registration statement on
Form S-3
registering issuances by unitholders of an aggregate of
5,386,732 of our common units. In addition, in February 2008, we
satisfied the financial tests contained in our partnership
agreement for the early conversion of 3,571,428, or 50%, of the
outstanding subordinated units held by DCP Midstream, LLC into
common units, and on February 17, 2009, we satisfied the
financial tests contained in our partnership agreement for the
early conversion of the remaining 3,571,429 outstanding
subordinated units held by DCP Midstream, LLC into common units.
After the conversion, DCP Midstream, LLC holds 8,246,451 common
units.
If investors or affiliates of our general partner holding these
units were to dispose of a substantial portion of these units in
the public market, whether in a single transaction or series of
transactions, it could reduce the market price of our
outstanding common units. In addition, these sales, or the
possibility that these sales may occur, could make it more
difficult for us to sell our common units in the future.
Our
general partner has a limited call right that may require the
unitholders to sell their units at an undesirable time or
price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of
the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, the
unitholders may be required to sell their common units at an
undesirable time or price and may not receive any return on
their investment. Unitholders may also incur a tax liability
upon a sale of their units.
The
liability of holders of limited partner interests may not be
limited if a court finds that unitholder action constitutes
control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly
established in some of the other states in which we do business.
Holders of limited partner interests could be liable for any and
all of our obligations as if such holder were a general partner
if:
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a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
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the right of holders of limited partner interests to act with
other unitholders to remove or replace the general partner, to
approve some amendments to our partnership agreement or to take
other actions under our partnership agreement constitute
control of our business.
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Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to the unitholders if the distribution
would cause our liabilities to exceed the fair value of our
assets. Delaware law provides that for a period of three years
from the date of the impermissible distribution, limited
partners who received the distribution and who knew at the time
of the distribution that it violated Delaware law will be liable
to the limited partnership for the distribution amount.
Substituted limited partners are liable for the obligations of
the assignor to make contributions to the partnership that are
known to the substituted limited partner at the time it became a
limited partner and for unknown obligations if the liabilities
could be determined from the partnership agreement. Liabilities
to partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
Tax Risks
to Common Unitholders
Our
tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our being subject to minimal
entity-level taxation by individual states. If the Internal
Revenue Service were to treat us as a corporation or we become
subject to a material amount of entity-level taxation for state
tax purposes, it would substantially reduce the amount of cash
available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS
regarding our status as a partnership.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based
upon our current operations that we will be treated as a
corporation, a change in our business (or a change in current
law) could cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to taxation as an
entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%
and would likely pay state income tax at varying rates.
Distributions to the unitholder would generally be taxed again
as corporate distributions, and no income, gains, losses or
deductions would flow through to them. Because a tax would be
imposed upon us as a corporation, our cash available for
distribution to the unitholder would be substantially reduced.
Therefore, treatment of us as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to the unitholders, likely causing a substantial
reduction in the value of our common units.
Current law may change, which would cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to entity-level taxation. At the federal level, legislation
has been proposed that would eliminate partnership tax treatment
for certain publicly traded partnerships. Although such
legislation would not apply to us as currently proposed, it
could be amended prior to enactment in a manner that does apply
to us. We are unable to predict whether any of these amendments
or other proposals will ultimately be enacted. Moreover, any
such modification to federal income tax laws and interpretations
thereof may or may not be applied retroactively. Any such
legislative changes could negatively impact the value of an
investment in our common units. In addition, because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. For example, we are
required to pay Texas franchise tax at a maximum effective rate
of 0.7% of our gross income apportioned to Texas in the prior
year and a Michigan business tax of 0.8% on gross receipts, and
4.95% of Michigan taxable income. Imposition of such a
46
tax on us by any other state will reduce the cash available for
distribution to the unitholder. The partnership agreement
provides that if a law is enacted or existing law is modified or
interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation
for federal, state or local income tax purposes, the minimum
quarterly distribution amount and the target distribution levels
will be adjusted to reflect the impact of that law on us.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted, and the
cost of any IRS contest will reduce our cash available for
distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
document or from the positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take.
A court may not agree with some or all of our counsels
conclusions or positions we take. Any contest with the IRS may
materially and adversely impact the market for our common units
and the price at which they trade. In addition, our costs of any
contest with the IRS will be borne indirectly by our unitholders
and our general partner because such costs will reduce our cash
available for distribution.
The
unitholder may be required to pay taxes on income from us even
if the unitholder does not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income, which could be different in amount
than the cash we distribute, the unitholder will be required to
pay any federal income taxes and, in some cases, state and local
income taxes on their share of our taxable income even if they
receive no cash distributions from us. The unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the tax liability that results
from that income.
Tax
gain or loss on disposition of common units could be more or
less than expected.
If the unitholder sells their common units, they will recognize
a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Because
distributions to the unitholders in excess of the total net
taxable income allocated to them for a common unit decreases
their tax basis in that common unit, the amount, if any, of such
prior excess distributions will, in effect, become taxable
income to them if the common unit is sold at a price greater
than their tax basis in that common unit, even if the price is
less than their original cost. Furthermore, a substantial
portion of the amount realized, whether or not representing
gain, may be taxed as ordinary income due to potential recapture
items, including depreciation recapture. In addition, because
the amount realized includes a unitholders share of our
nonrecourse liabilities, if the unitholder sells their units,
they may incur a tax liability in excess of the amount of cash
they receive from the sale.
Tax-exempt
entities and
non-U.S.
persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), other retirement
plans and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income, which may be taxable to them.
Distributions to
non-U.S. persons
will be reduced by federal withholding taxes at the highest
applicable effective tax rate, and
non-U.S. persons
will be required to file United States federal tax returns and
pay tax on their share of our taxable income. If the unitholder
is a tax-exempt entity or a
non-U.S. person,
they should consult their tax advisor before investing in our
common units.
47
We
will treat each purchaser of our common units as having the same
tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could
adversely affect the value of the common units.
Because we cannot match transferors and transferees of common
units and because of other reasons, we will adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to the unitholder. It also could affect the
timing of these tax benefits or the amount of gain from the sale
of common units and could have a negative impact on the value of
our common units or result in audit adjustments to the
unitholders tax returns.
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury Regulations. If the IRS were
to challenge this method or new Treasury regulations were
issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered as having
disposed of those units. If so, he would no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our
income, gain, loss or deduction with respect to those units may
not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
We
have adopted certain valuation methodologies that may result in
a shift of income, gain, loss and deduction between the general
partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common
units.
When we issue additional units or engage in certain other
transactions, we determine the fair market value of our assets
and allocate any unrealized gain or loss attributable to our
assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, subsequent purchasers of common units may
have a greater portion of their Internal Revenue Code
Section 743(b) adjustment allocated to our tangible assets
and a lesser portion allocated to our intangible assets. The IRS
may challenge our valuation methods, or our allocation of the
Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and
deduction between the general partner and certain of our
unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
48
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a twelve-month
period. Our termination would, among other things, result in the
closing of our taxable year for all unitholders, which would
result in us filing two tax returns (and our unitholders could
receive two
Schedule K-1s)
for one fiscal year and could result in a significant deferral
of depreciation deductions allowable in computing our taxable
income. In the case of a unitholder reporting on a taxable year
other than a fiscal year ending December 31, the closing of
our taxable year may result in more than twelve months of our
taxable income or loss being includable in his taxable income
for the year of termination. Our termination currently would not
affect our classification as a partnership for federal income
tax purposes, but instead, we would be treated as a new
partnership for tax purposes. If treated as a new partnership,
we must make new tax elections and could be subject to penalties
if we are unable to determine that a termination occurred.
Unitholders
may be subject to state and local taxes and return filing
requirements in states where they do not reside as a result of
investing in our units.
In addition to federal income taxes, the unitholder may be
subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions
in which we conduct business or own property, even if the
unitholder does not live in any of those jurisdictions. The
unitholder may be required to file foreign, state and local
income tax returns and pay state and local income taxes in some
or all of these jurisdictions. Further, the unitholder may be
subject to penalties for failure to comply with those
requirements. We own assets and conduct business in the states
of Arkansas, Colorado, Connecticut, Indiana, Kentucky,
Louisiana, Maine, Maryland, Massachusetts, Michigan, New
Hampshire, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island,
Tennessee, Texas, Vermont, Virginia, West Virginia and Wyoming.
Each of these states, other than Texas and Wyoming, currently
imposes a personal income tax on individuals. A majority of
these states impose an income tax on corporations and other
entities. As we make acquisitions or expand our business, we may
own assets or do business in additional states that impose a
personal income tax. It is the unitholders responsibility
to file all United States federal, foreign, state and local tax
returns.
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Item 1B.
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Unresolved
Staff Comments
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None.
As of February 23, 2009, we owned and operated processing
plants and gathering systems located in Arkansas, Colorado,
Louisiana, Michigan, Oklahoma, and Wyoming, all within our
Natural Gas Services segment, six propane rail terminals located
in the midwest and northeastern United States, one of which is
was idled in 2007 to consolidate our operations, and one propane
pipeline terminal located in Pennsylvania within our Wholesale
Propane Logistics Segment, and two pipelines located in Texas
within our NGL Logistics segment. In addition, we own (1) a
40% interest in Discovery Producer Services, LLC, which owns an
offshore gathering pipeline, a natural gas processing plant and
an NGL fractionator plant in Louisiana operated by a third
party, and (2) a 25% interest in DCP East Texas Holdings,
LLC, which owns a natural gas processing complex in Texas, all
within our Natural Gas Services Segment. We also own a 45%
interest in the Black Lake pipeline located in Louisiana and
Texas operated by a third party within our NGL Logistics
segment, and a 50% interest in a propane rail terminal located
in Maine within our Wholesale Propane Logistics segment. For
additional details on these plants, propane terminals and
pipeline systems, please read Business Natural
Gas Services Segment, Business Wholesale
Propane Logistics Segment and Business
NGL Logistics Segment. We believe that our properties are
generally in good condition, well maintained and are suitable
and adequate to carry on our business at capacity for the
foreseeable future.
49
Our real property falls into two categories: (1) parcels
that we own in fee; and (2) parcels in which our interest
derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities permitting
the use of such land for our operations. Portions of the land on
which our plants and other major facilities are located are
owned by us in fee title, and we believe that we have
satisfactory title to these lands. The remainder of the land on
which our plant sites and major facilities are located are held
by us pursuant to ground leases between us, as lessee, and the
fee owner of the lands, as lessors. We, or our predecessors,
have leased these lands for many years without any material
challenge known to us relating to the title to the land upon
which the assets are located, and we believe that we have
satisfactory leasehold estates to such lands. We have no
knowledge of any challenge to the underlying fee title of any
material lease, easement, right-of-way, permit or license held
by us or to our title to any material lease, easement,
right-of-way, permit or lease, and we believe that we have
satisfactory title to all of our material leases, easements,
rights-of-way, permits and licenses.
Our principal executive offices are located at 370
17th Street, Suite 2775, Denver, Colorado 80202, our
telephone number is
303-633-2900
and our website address is www.dcppartners.com.
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Item 3.
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Legal
Proceedings
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We are not a party to any significant legal proceedings, other
than those listed below, but are a party to various
administrative and regulatory proceedings that have arisen in
the ordinary course of our business. Management currently
believes that the ultimate resolution of these matters, taken as
a whole, and after consideration of amounts accrued, insurance
coverage or other indemnification arrangements, will not have a
material adverse effect upon our consolidated results of
operations, financial position or cash flows. Please read
Business Regulation of Operations and
Business Environmental Matters.
Driver In August 2007, Driver Pipeline
Company, Inc., or Driver, filed a lawsuit against DCP Midstream,
LP, an affiliate of the owner of our general partner, in
District Court, Jackson County, Texas. The litigation stems from
an ongoing commercial dispute involving the construction of our
Wilbreeze pipeline, which was completed in December 2006. Driver
was the primary contractor for construction of the pipeline and
the construction process was managed for us by DCP Midstream,
LP. Driver claims damages in the amount of $2.4 million for
breach of contract. We believe Drivers position in this
litigation is without merit and we intend to vigorously defend
ourselves against this claim. It is not possible to predict
whether we will incur any liability or to estimate the damages,
if any, we might incur in connection with this matter.
Management does not believe the ultimate resolution of this
issue will have a material adverse effect on our consolidated
results of operations, financial position or cash flows.
El Paso On February 27, 2009, a
jury in the District Count, Harris County, Texas rendered a
verdict in favor of El Paso E&P Company, L.P. and
against one of our subsidiaries and DCP Midstream. As previously
disclosed, the lawsuit, filed in December 2006, stems from an
ongoing commercial dispute involving our Minden processing plant
that dates back to August 2000, which includes periods of time
prior to our ownership of this asset. Our responsibility for
this judgment will be limited to the time period after we
acquired the asset from DCP Midstream in December 2005. We
intend to appeal this decision and will continue to defend
ourselves vigorously against this claim. Nevertheless, as a
result of the jury verdict we have reserved, in accordance with
accounting principles generally accepted in the United States of
America, a contingent liability of $2.5 million for this
matter, which is included in our consolidated financial
statements for the year ended December 31, 2008. This
reserve changes our financial results as reported in our
earnings release dated February 25, 2009, which date
preceded the jury verdict.
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Item 4.
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Submission
of Matters to a Vote of Unitholders
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No matters were submitted to a vote of our limited partner
unitholders, through solicitation of proxies or otherwise,
during 2008.
50
PART II
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Item 5.
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Market
for Registrants Common Equity, and Related Unitholder
Matters and Issuer Purchases of Units
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Market
Information
Our common units have been listed on the New York Stock
Exchange, or the NYSE, under the symbol DPM since
December 2, 2005. Prior to December 2, 2005, our
equity securities were not listed on any exchange or traded on
any public trading market. The following table sets forth the
high and low closing sales prices of the common units, as
reported by the NYSE, as well as the amount of cash
distributions declared per quarter for 2008 and 2007.
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Distribution Per
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Distribution Per
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Common
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Subordinated
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Quarter Ended
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High
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Low
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Unit
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Unit
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December 31, 2008
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$
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16.94
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$
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5.75
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$
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0.600
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$
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0.600
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September 30, 2008
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$
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30.21
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$
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16.92
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$
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0.600
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$
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0.600
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June 30, 2008
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$
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31.51
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$
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28.98
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$
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0.600
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$
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0.600
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March 31, 2008
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$
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43.51
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$
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27.37
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$
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0.590
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$
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0.590
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December 31, 2007
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$
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45.95
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$
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37.68
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$
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0.570
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$
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0.570
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September 30, 2007
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$
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50.50
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|
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$
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41.75
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$
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0.550
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$
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0.550
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June 30, 2007
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$
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47.00
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$
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38.15
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$
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0.530
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$
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0.530
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March 31, 2007
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$
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40.06
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$
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33.99
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$
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0.465
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$
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0.465
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As of February 23, 2009, there were approximately 47
unitholders of record of our common units. This number does not
include unitholders whose units are held in trust by other
entities. The actual number of unitholders is greater than the
number of holders of record.
51
Issuance
of Unregistered Units
In February 2008, we satisfied the financial tests contained in
our partnership agreement for the early conversion of 50% of the
outstanding subordinated units held by DCP Midstream, LLC into
common units on a one-for-one basis. Before the conversion, DCP
Midstream, LLC held 7,142,857 subordinated units, and after the
conversion, DCP Midstream, LLC held 3,571,429 subordinated
units. On February 17, 2009, we satisfied the financial
tests contained in our partnership agreement for the early
conversion of the remaining 3,571,429 outstanding subordinated
units held by DCP Midstream, LLC into common units on a one for
one basis.
Distributions
of Available Cash
General Our partnership agreement
requires that, within 45 days after the end of each
quarter, we distribute all of our Available Cash (defined below)
to unitholders of record on the applicable record date, as
determined by our general partner.
In January 2008, our registration statement on
Form S-3
to register the 3,005,780 common limited partner units
represented in the June 2007 private placement agreement and the
2,380,952 common limited partner units represented in the August
2007 private placement agreement was declared effective by the
SEC.
In March 2008, we issued 4,250,000 common limited partner units
at $32.44 per unit, and received proceeds of
$132.1 million, net of offering costs.
Definition of Available
Cash Available Cash, for any quarter,
consists of all cash and cash equivalents on hand at the end of
that quarter:
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less the amount of cash reserves established by our general
partner to:
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provide for the proper conduct of our business;
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comply with applicable law, any of our debt instruments or other
agreements; or
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provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters;
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plus, if our general partner so determines, all or a portion of
cash and cash equivalents on hand on the date of determination
of Available Cash for the quarter.
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Minimum Quarterly Distribution The
Minimum Quarterly Distribution, as set forth in the partnership
agreement, is $0.35 per unit per quarter, or $1.40 per unit per
year. Our current quarterly distribution is $0.60 per unit, or
$2.40 per unit annualized. There is no guarantee that we will
maintain our current distribution or pay the Minimum Quarterly
Distribution on the units in any quarter. Even if our cash
distribution policy is not modified or revoked, the amount of
distributions paid under our policy and the decision to make any
distribution is determined by our general partner, taking into
consideration the terms of our partnership agreement. We will be
prohibited from making any distributions to unitholders if it
would cause an event of default, or an event of default exists,
under our credit agreement. Please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Capital Requirements
Description of Credit Agreement for a discussion of the
restrictions included in our credit agreement that may restrict
our ability to make distributions.
General Partner Interest and Incentive Distribution Rights
Prior to June 2007, our general partner was
entitled to 2% of all quarterly distributions since inception
that we made. Our general partner has the right, but not the
obligation, to contribute a proportionate amount of capital to
us to maintain its current general partner interest. The general
partner has not participated in certain issuances of common
units. Therefore, the general partners 2% interest has
been diluted to approximately 1% as of December 31, 2008.
The general partners interest may be further reduced if we
issue additional units in the future and our general partner
does not contribute a proportionate amount of capital to us to
maintain its current general partner interest.
52
The incentive distribution rights held by our general partner
entitle it to receive an increasing share of Available Cash as
pre-defined distribution targets have been achieved. Currently,
our distribution to our general partner related to its incentive
distribution rights is at the highest level. Our general
partners incentive distribution rights were not reduced as
a result of our March 2008 common limited partner unit offering,
and will not be reduced if we issue additional units in the
future and the general partner does not contribute a
proportionate amount of capital to us to maintain its current
general partner interest. Please read the Distributions of
Available Cash during the Subordination Period and
Distributions of Available Cash after the Subordination
Period sections in Note 12 of the Notes to Consolidated
Financial Statements in Item 8. Financial Statements
and Supplementary Data for more details about the
distribution targets and their impact on the general
partners incentive distribution rights.
On January 27, 2009, the board of directors of DCP
Midstream GP, LLC declared a quarterly distribution of $0.60 per
unit, which was paid on February 13, 2009, to unitholders
of record on February 6, 2009.
Equity
Compensation Plans
The information relating to our equity compensation plans
required by Item 5 is incorporated by reference to such
information as set forth in Item 12. Security
Ownership of Certain Beneficial Owners and Management and
Related Unitholder Matters contained herein.
53
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Item 6.
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Selected
Financial Data
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The following table shows our selected financial data for the
periods and as of the dates indicated, which is derived from the
consolidated financial statements. These consolidated financial
statements include our accounts, and prior to December 7,
2005, the assets, liabilities and operations contributed to us
by DCP Midstream, LLC and its wholly-owned subsidiaries, or DCP
Midstream Partners Predecessor, upon the closing of our initial
public offering, which have been combined with the historical
assets, liabilities and operations of our wholesale propane
logistics business which we acquired from DCP Midstream, LLC in
November 2006, and our 25% limited liability company interest in
DCP East Texas Holdings, LLC, or East Texas, our 40% limited
liability company interest in Discovery Producer Services, LLC,
or Discovery, and a non-trading derivative instrument, or the
Swap, which DCP Midstream, LLC entered into in March 2007, which
we acquired from DCP Midstream, LLC in July 2007. These were
transactions among entities under common control; accordingly,
our financial information includes the historical results of our
wholesale propane logistics business, Discovery and East Texas
for all periods presented. The information contained herein
should be read together with, and is qualified in its entirety
by reference to, the consolidated financial statements and the
accompanying notes included elsewhere in this
Form 10-K.
Our operating results incorporate a number of significant
estimates and uncertainties. Such matters could cause the data
included herein to not be indicative of our future financial
conditions or results of operations. A discussion on our
critical accounting estimates is included in
Managements Discussion and Analysis of Financial
Condition and Results of Operations.
The table should also be read together with
Managements Discussion and Analysis of Financial
Condition and Results of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008(a)
|
|
|
2007(a)
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Millions, except per unit data)
|
|
|
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues(b)
|
|
$
|
1,285.8
|
|
|
$
|
873.3
|
|
|
$
|
795.8
|
|
|
$
|
1,144.3
|
|
|
$
|
834.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas, propane and NGLs
|
|
|
1,061.2
|
|
|
|
826.7
|
|
|
|
700.4
|
|
|
|
1,047.3
|
|
|
|
760.6
|
|
Operating and maintenance expense
|
|
|
43.0
|
|
|
|
32.1
|
|
|
|
23.7
|
|
|
|
22.4
|
|
|
|
19.8
|
|
Depreciation and amortization expense
|
|
|
36.5
|
|
|
|
24.4
|
|
|
|
12.8
|
|
|
|
12.7
|
|
|
|
14.7
|
|
General and administrative expense
|
|
|
24.0
|
|
|
|
24.1
|
|
|
|
21.0
|
|
|
|
14.2
|
|
|
|
8.7
|
|
Other
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,163.2
|
|
|
|
907.3
|
|
|
|
757.9
|
|
|
|
1,096.6
|
|
|
|
803.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
122.6
|
|
|
|
(34.0
|
)
|
|
|
37.9
|
|
|
|
47.7
|
|
|
|
30.2
|
|
Interest income
|
|
|
5.6
|
|
|
|
5.3
|
|
|
|
6.3
|
|
|
|
0.5
|
|
|
|
|
|
Interest expense
|
|
|
(32.8
|
)
|
|
|
(25.8
|
)
|
|
|
(11.5
|
)
|
|
|
(0.8
|
)
|
|
|
|
|
Earnings from equity method investments(c)
|
|
|
34.3
|
|
|
|
39.3
|
|
|
|
29.2
|
|
|
|
25.7
|
|
|
|
17.6
|
|
Impairment of equity method investment(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4.4
|
)
|
Non-controlling interest in income
|
|
|
(3.9
|
)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense(e)
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
(3.3
|
)
|
|
|
(2.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
|
$
|
69.8
|
|
|
$
|
40.9
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to predecessor operations(f)
|
|
|
|
|
|
|
(3.6
|
)
|
|
|
(26.6
|
)
|
|
|
(65.1
|
)
|
|
|
(40.9
|
)
|
General partner interest in net income
|
|
|
(11.9
|
)
|
|
|
(2.2
|
)
|
|
|
(0.7
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to limited partners
|
|
$
|
113.8
|
|
|
$
|
(21.6
|
)
|
|
$
|
34.6
|
|
|
$
|
4.6
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit-basic and diluted
|
|
$
|
3.25
|
|
|
$
|
(1.05
|
)
|
|
$
|
1.90
|
|
|
$
|
0.20
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008(a)
|
|
|
2007(a)
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Millions, except per unit data)
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
629.3
|
|
|
$
|
500.7
|
|
|
$
|
194.7
|
|
|
$
|
178.7
|
|
|
$
|
179.3
|
|
Total assets
|
|
$
|
1,180.0
|
|
|
$
|
1,120.7
|
|
|
$
|
665.9
|
|
|
$
|
680.1
|
|
|
$
|
472.5
|
|
Accounts payable
|
|
$
|
78.4
|
|
|
$
|
165.8
|
|
|
$
|
117.3
|
|
|
$
|
138.3
|
|
|
$
|
63.5
|
|
Long-term debt
|
|
$
|
656.5
|
|
|
$
|
630.0
|
|
|
$
|
268.0
|
|
|
$
|
210.1
|
|
|
$
|
|
|
Partners equity
|
|
$
|
329.1
|
|
|
$
|
168.4
|
|
|
$
|
267.7
|
|
|
$
|
320.7
|
|
|
$
|
400.5
|
|
Other Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
|
|
$
|
2.390
|
|
|
$
|
2.115
|
|
|
$
|
1.565
|
|
|
$
|
0.095
|
|
|
|
N/A
|
|
Cash distributions paid per unit
|
|
$
|
2.360
|
|
|
$
|
1.975
|
|
|
$
|
1.230
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
(a) |
|
Includes the effect of the acquisition of the Southern Oklahoma
system in May 2007, certain subsidiaries of Momentum Energy
Group, Inc. in August 2007 and Michigan Pipeline &
Processing, LLC in October 2008. |
|
(b) |
|
Includes the effect of the acquisition of the Swap entered into
by DCP Midstream, LLC in March 2007. The Swap was for a total of
approximately 1.9 million barrels at $66.72 per barrel. |
|
(c) |
|
Includes the effect of the acquisition of a 25% limited
liability company interest in East Texas and a 40% limited
liability company interest in Discovery for all periods
presented, as well our proportionate share of the earnings of
Black Lake, East Texas and Discovery. Earnings for Discovery and
Black Lake include the amortization of the net difference
between the carrying amount of the investments and the
underlying equity of the investments. |
|
(d) |
|
In 2004, we recorded our proportionate share of an impairment
charge on Black Lake totaling $4.4 million. |
|
(e) |
|
Income tax expense for 2004 through 2005 is applicable to the
results of operations of our wholesale propane logistics
business. We incurred no income tax expense in 2006, due to the
change in tax status of our wholesale propane logistics business
in December 2005. Income tax expense in 2008 and 2007 represents
a margin-based franchise tax in Texas, or the Texas margin tax
and a Michigan business tax. See Note 15 of the Notes to
Consolidated Financial Statements in Item 8.
Financial Statements and Supplementary Data. |
|
(f) |
|
Includes the net income attributable to DCP Midstream Partners
Predecessor through December 7, 2005, the net income (loss)
attributable to our wholesale propane logistics business prior
to the date of our acquisition from DCP Midstream, LLC in
November 2006, and the net income attributable to the
acquisition of a 25% limited liability company interest in East
Texas, a 40% limited liability company interest in Discovery,
and the Swap prior to the date of our acquisition from DCP
Midstream, LLC in July 2007. |
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion analyzes our financial condition and
results of operations. You should read the following discussion
of our financial condition and results of operations in
conjunction with our consolidated financial statements and notes
included elsewhere in this annual report. We refer to the
assets, liabilities and operations contributed to us by DCP
Midstream, LLC and its wholly-owned subsidiaries upon the
closing of our initial public offering as DCP Midstream Partners
Predecessor, which have been combined with the historical
assets, liabilities and operations of our wholesale propane
logistics business, which we acquired from DCP Midstream, LLC in
November 2006, and our 25% limited liability company interest in
DCP East Texas Holdings, LLC, or East Texas, our 40% limited
liability company interest in Discovery Producer Services, LLC,
or Discovery, and a non-trading derivative instrument, or the
Swap, which DCP Midstream, LLC entered into in March 2007, which
we acquired from DCP Midstream, LLC in July 2007. We refer to
DCP Midstream Partners Predecessor, our wholesale propane
logistics business, East Texas and Discovery
55
collectively as our predecessors. The financial
information contained herein includes, for each period
presented, our accounts, and those of our predecessors.
Overview
We are a Delaware limited partnership formed by DCP Midstream,
LLC to own, operate, acquire and develop a diversified portfolio
of complementary midstream energy assets. We operate in three
business segments:
|
|
|
|
|
our Natural Gas Services segment, which consists of (1) our
Northern Louisiana natural gas gathering, processing and
transportation system; (2) our Southern Oklahoma system
acquired in May 2007; (3) our limited liability company
interest in East Texas, our limited liability company interest
in Discovery, and the Swap, acquired in July 2007 from DCP
Midstream, LLC; (4) our Colorado and Wyoming systems,
acquired in August 2007 from DCP Midstream, LLC, which were
acquired by DCP Midstream, LLC from Momentum Energy Group, Inc.,
or MEG, in August 2007 (referred to as the MEG acquisition); and
(5) our Michigan systems, acquired in October 2008 from
Michigan Pipeline & Processing, LLC (referred to as
the MPP acquisition);
|
|
|
|
our Wholesale Propane Logistics segment, which consists of six
owned rail terminals, one of which was idled in 2007 to
consolidate our operations, one leased marine terminal, one
pipeline terminal which became operational in May 2007, and
access to several open access pipeline terminals; and
|
|
|
|
our NGL Logistics segment, which consists of our Seabreeze and
Wilbreeze NGL transportation pipelines, and a non-operated
equity interest in the Black Lake interstate NGL pipeline.
|
The financial information contained herein includes, for each
period presented, our accounts, and the assets, liabilities and
operations of (1) DCP Midstream Partners Predecessor for
periods prior to December 7, 2005, (2) our wholesale
propane logistics business that we acquired in November 2006 and
(3) our 25% interest in East Texas, 40% interest in
Discovery, and the Swap that we acquired in July 2007, from DCP
Midstream, LLC in transactions among entities under common
control. Accordingly, our financial information includes the
historical results of our predecessors for all periods
presented. The historical financial statements of DCP Midstream
Partners Predecessor included in this annual report and
discussed elsewhere herein include DCP Midstream Partners
Predecessors 50% ownership interest in Black Lake Pipe
Line Company, or Black Lake. However, effective December 7,
2005, DCP Midstream, LLC retained a 5% interest and we own a 45%
interest in Black Lake.
Recent
Events
On February 27, 2009, a jury in the District Count, Harris
County, Texas rendered a verdict in favor of El Paso
E&P Company, L.P. and against one of our subsidiaries and
DCP Midstream. As previously disclosed, the lawsuit, filed in
December 2006, stems from an ongoing commercial dispute
involving our Minden processing plant that dates back to August
2000, which includes periods of time prior to our ownership of
this asset. Our responsibility for this judgment will be limited
to the time period after we acquired the asset from DCP
Midstream in December 2005. We intend to appeal this decision
and will continue to defend ourselves vigorously against this
claim. Nevertheless, as a result of the jury verdict we have
reserved in accordance with accounting principles generally
accepted in the United States of America, or GAAP, a contingent
liability of $2.5 million for this matter, which is
included in our consolidated financial statements for the year
ended December 31, 2008. This reserve changes our financial
results as reported in our earnings release dated
February 25, 2009, which date preceded the jury verdict.
On February 25, 2009, we entered into a Contribution
Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC
will contribute an additional 25.1% interest in East Texas to us
in exchange for 3.5 million Class D units, providing
us with a 50.1% interest in East Texas following the expected
closing of the transaction in April 2009. This closing date is
subject to extension for up to 45 days to allow for repairs
or replacement to our reasonable satisfaction any assets
destroyed or damaged by certain casualty losses and time to
enable the plant to process all available inlet volumes as
defined in the Contribution Agreement. The Class D units
will automatically convert into common units in August 2009 and
will not be eligible to receive
56
a distribution until the second quarter distribution payable in
August 2009. DCP Midstream, LLC has agreed to provide a
fixed-price NGL derivative by NGL component for the period of
April 2009 to March 2010 for the acquired interest. Subsequent
to this transaction, we will consolidate East Texas in our
consolidated financial statements.
On February 11, 2009, we announced, along with DCP
Midstream, LLC, that our East Texas natural gas processing
complex and residue natural gas delivery system known as the
Carthage Hub, have been temporarily shut in following a fire
that was caused by a third party underground pipeline outside of
our property line that ruptured. No employees or contractors
were injured in the incident. There was no significant damage to
the natural gas processing complex. As of February 25,
2009, the complex began processing through one of the five
plants, and it is expected that full processing capacities will
be restored for the entire complex over the next 30 days.
Residue gas will be redelivered into limited available pipeline
interconnects while the Carthage Hub undergoes inspection and
repairs.
On February 17, 2009, the remaining 3,571,429 DCP Partners
subordinated units were converted to common units following the
completion of the subordination period and satisfactory
completion of all subordination period tests contained in the
DCP Partners partnership agreement.
In February 2009, we entered into interest rate swap agreements
to convert $275.0 million of the indebtedness on our
revolving credit facility to a fixed rate obligation, thereby
reducing the exposure to interest rate fluctuations. These
interest rate swaps commence in December 2010 and expire in June
2012. In November 2008, we entered into interest rate swap
agreements to convert $150.0 million of the indebtedness on
our revolving credit facility to a fixed rate obligation,
thereby reducing the exposure to interest rate fluctuations.
These interest rate swaps expire in December 2010.
As a result of hurricanes during the third quarter of 2008,
certain of our owned and operated facilities were fully or
partially curtailed pending resumption of electric power and
operations at downstream third party NGL facilities, in some
cases. All of our operated assets have since been returned to
service. There has been some temporary impact to demand as third
party NGL facilities are returned to service. The net income
impact of hurricane-related damages and lost margins due to
curtailed operations for the third and fourth quarters of 2008
was approximately $14.7 million, including losses from our
equity method investment in Discovery.
In January 2009, repairs were completed on Discoverys
30-inch
mainline, restoring approximately 85% of volumes and margins to
the system. With the completion of the
18-inch
lateral repairs, the remaining volumes are expected to be
restored in early March. We did not receive a fourth quarter
distribution from Discovery, which would have been paid during
January 2009. We anticipate distributions to resume for the
first quarter of 2009, which will be paid in April 2009.
Discoverys offshore gathering system had been damaged by
hurricane Ike in September 2008 when an
18-inch
lateral was severed from its connection to the
30-inch
mainline in 250 feet of water.
On January 27, 2009, the board of directors of the general
partner declared a quarterly distribution of $0.60 per unit,
payable on February 13, 2009 to unitholders of record on
February 6, 2009.
In January 2009, Don Baldridge was appointed to Vice President,
Business Development. Previously, Mr. Baldridge was Vice
President, Corporate Development for DCP Midstream, LLC.
Mr. Baldridge is replacing Greg K. Smith, who was appointed
Vice President, Gas Supply for DCP Midstream, LLC.
In early January 2009, the second phase of our Wyoming pipeline
and systems enhancement project was completed, returning over
80% of the system volumes to service. The final phase is on
target for completion in March.
In December 2008, we made contributions of $1.9 million to
Discovery, $1.6 million of which was to fund hurricane
damages and $0.3 million was to fund capital expansion. In
December 2008 we received a distribution of $2.5 million
from East Texas and paid a contribution of $2.6 million to
East Texas to fund capital expansion.
In October 2008, due to executive management rotational changes
at ConocoPhillips, Willie C.W. Chiang and Sigmund L. Cornelius
resigned as directors of the board of directors of our general
partner, and John E.
57
Lowe and Gregory J. Goff were appointed as the ConocoPhillips
representatives to the board of directors. Mr. Lowe
currently serves as assistant to the Chief Executive Officer of
ConocoPhillips, an affiliate of our general partner and
Mr. Goff currently serves as Senior Vice President,
Commercial of ConocoPhillips. Mr. Goff was also appointed
to DCP Partners compensation committee in December 2008.
In October 2008, we acquired Michigan Pipeline &
Processing, LLC, or MPP, a privately held company engaged in
natural gas gathering and treating services for natural gas
produced from the Antrim Shale of northern Michigan and natural
gas transportation within Michigan. Under the terms of the
acquisition, we paid a purchase price of $145.0 million,
plus net working capital and other adjustments of
$3.4 million, subject to additional customary purchase
price adjustments, plus up to an additional $15.0 million
to the sellers depending on the earnings of the assets after a
three-year period. We financed the acquisition through
utilization of our credit facility. In addition, we entered into
a separate agreement that provides the seller with available
treating capacity on certain Michigan assets. The seller agreed
to pay us up to $1.5 million annually for up to nine years
if they do not meet certain criteria, including providing
additional volumes for treatment. These payments would reduce
goodwill as a return of purchase price. This agreement may be
terminated earlier if certain performance criteria of Michigan
assets are satisfied. Certain of these performance criteria were
satisfied, and as a result, the amount has been reduced to
$0.8 million per year as of February 23, 2009. We
initially held a $25.0 million letter of credit to secure
the sellers performance under this agreement and to secure
the sellers indemnification obligation under the
acquisition agreement; however as a result of the satisfaction
of certain performance conditions, this amount has been reduced
to $22.5 million as of February 23, 2009. The fees
under the omnibus agreement with DCP Midstream, LLC increased
$0.4 million per year effective October 1, 2008, in
connection with the acquisition.
Factors
That Significantly Affect Our Results
Capital
Markets
Beginning in the third quarter of 2008, the capital markets
experienced volatility, uncertainty and interventions by various
governments around the globe. The effects of these market
conditions include significant changes in the valuation of
equity securities and overnight and longer-term borrowing rates.
The availability of credit through traditional sources of
funding such as the commercial paper, bank lending and the
private and public placement debt markets also decreased
dramatically. The uncertainty in the capital markets may impact
our business in multiple ways, including limiting our
producers ability to finance their drilling programs and
limiting our ability to grow our operations through acquisitions
or organic growth projects. These events may impact our
counterparties ability to perform under their credit or
commercial obligations. While we did not experience significant
collection issues during 2008, we continue to monitor the
payment patterns of our customers. Where possible, we have
obtained additional collateral agreements, letters of credit
from highly rated banks, or have managed credit lines. To date,
our counterparties to our existing derivative instruments have
fully performed under their commitments. Due to the bankruptcy
of Lehman Brothers Commercial Bank, or Lehman Brothers, a lender
to our Credit Agreement, the availability of borrowings under
this facility has been reduced by approximately
$25.4 million. Accordingly, the capacity under our Credit
Agreement is approximately $824.6 million, excluding Lehman
Brothers unfunded commitment.
Impact
of Severe Weather
The economic impact of severe weather may negatively affect the
nations short-term energy supply and demand, and may
result in increased commodity prices. Additionally, severe
weather may restrict or prevent us from fully utilizing our
assets, by damaging our assets, interrupting utilities, and
through possible NGL and natural gas curtailments downstream of
our facilities, which restricts our production. These impacts
may linger past the time of the actual weather event. Severe
weather may also impact the supply and demand in our wholesale
propane business.
58
Other
Factors
Natural
Gas Services Segment
Our results of operations for our Natural Gas Services segment
are impacted by (1) increases and decreases in the volume
of natural gas that we gather and transport through our systems,
which we refer to as throughput, (2) prices of commodities
such as NGLs, crude oil and natural gas, (3) the operating
efficiency of our processing facilities, and (4) potential
limitations on throughput volumes arising from downstream and
infrastructure capacity constraints. Throughput and operating
efficiency generally are driven by wellhead production, plant
recoveries, operating availability of our facilities, physical
integrity and our competitive position on a regional basis, and
more broadly by demand for natural gas, NGLs and condensate.
Historical and current trends in the price changes of
commodities may not be indicative of future trends. Throughput
and prices are also driven by demand and take-away capacity for
residue natural gas and NGLs.
Natural Gas Services segment results of operations are also
impacted by the fees we receive and the margins we generate. Our
processing contract arrangements can have a significant impact
on our profitability and cash flow. Our actual contract terms
are based upon a variety of factors, including natural gas
quality, geographic location, commodity pricing environment at
the time the contract is executed, and customer requirements.
Our gathering and processing contract mix and, accordingly, our
exposure to natural gas, NGL and condensate prices, may change
as a result of producer preferences, impacting our expansion in
regions where certain types of contracts are more common and
other market factors.
Additionally, our results of operations for our Natural Gas
Services segment are impacted by market conditions causing
variability in natural gas, crude oil and NGL prices. The
midstream natural gas industry is cyclical, with the operating
results of companies in the industry significantly affected by
the prevailing price of NGLs, which in turn has been generally
correlated to the price of crude oil, except in recent periods,
when NGL pricing has been at a greater discount to crude oil
pricing. Although the prevailing price of residue natural gas
has less short-term significance to our operating results than
the price of NGLs, in the long term the growth and
sustainability of our business depends on natural gas prices
being at levels sufficient to provide incentives and capital,
for producers to increase natural gas exploration and
production. The prices of NGLs, crude oil and natural gas can be
extremely volatile for periods of time, and may not always have
a close correlation. Changes in the correlation of the price of
NGLs and crude oil may cause our commodity price sensitivities
to vary.
While pricing impacts the Natural Gas Services segment, we have
mitigated a significant portion of the anticipated commodity
price risk associated with the equity volumes from our gathering
and processing operations, for both our consolidated entities
and our proportionate share of exposure from our equity method
investments, through 2013 with fixed price natural gas and crude
oil swaps. We mark these derivative instruments to market
through current period earnings based upon their fair value.
While the swaps may mitigate the variability of our future cash
flows resulting from changes in commodity prices, the
mark-to-market method of accounting significantly increases the
volatility of our net income because we recognize, in current
period operating revenues, all non-cash gains and losses from
the changes in the fair value of these derivatives. We primarily
use crude oil swaps to mitigate our NGL and condensate commodity
price risk. As a result, the volatility of our future cash flows
and net income may increase if there is a change in the pricing
relationship between crude oil and NGLs. We also continue to
have price risk exposure related to the portion of our equity
volumes that are not covered by these derivatives and we have
financial risk exposure to the extent our actual equity volumes
differ from our projections. For additional information
regarding our derivative activities, please read
Quantitative and Qualitative Disclosures about
Market Risk Commodity Price Risk
Commodity Cash Flow Protection Activities.
Based on historical trends, however, we generally expect NGL
prices to follow changes in crude oil prices over the long term,
which we believe will in large part be determined by the level
of production from major crude oil exporting countries and the
demand generated by growth in the world economy. We believe that
future natural gas prices will be influenced by supply
deliverability, the severity of winter and summer weather, and
the domestic production and drilling activity level of
exploration and production companies. Drilling activity can be
adversely affected as natural gas prices decrease. Energy market
uncertainty could also
59
reduce North American drilling activity in the future. Limited
access to capital could also decrease drilling. Lower drilling
levels over a sustained period would have a negative effect on
natural gas volumes gathered and processed, but could increase
commodity prices, if supply were to fall below demand levels.
Wholesale
Propane Logistics Segment
Our results of operations for our Wholesale Propane Logistics
segment are impacted by our ability to balance our purchases and
sales of propane, which may increase our exposure to commodity
price risks. We may mitigate a portion of the anticipated
commodity price risk associated with fixed price propane sales
by entering into either offsetting physical purchase agreements
or financial derivative instruments, with DCP Midstream, LLC or
third parties, which typically match the quantities of propane
subject to these fixed price sales agreements. There may be an
impact on sales volumes from weather conditions in the midwest
and northeastern areas of the United States. Our annual sales
volumes of propane may decline when these areas experience
periods of milder weather in the winter months. Volumes may also
be impacted by conservation and reduced demand in the current
recessionary environment.
NGL
Logistics Segment
Our results of operations for our NGL Logistics segment are
impacted by the throughput volumes of the NGLs we transport on
our NGL pipelines, as we transport NGLs exclusively on a fee
basis. Throughput may be negatively impacted as a result of our
customers operating their processing plants in ethane rejection
mode, often as a result of low commodity prices for ethane.
During the fourth quarter of 2008, we did experience reduced
throughput due to ethane rejection at certain plants. Factors
that impact the supply and demand of NGLs, as described above in
our Natural Gas Services segment, may also impact the throughput
for our NGL Logistics segment.
Other
The above factors, including further sustained deterioration in
commodity prices, volumes or other market declines, including a
decline in our unit price, may negatively impact our results of
operations, and may increase the likelihood of a non-cash
impairment charge or non-cash lower of cost or market inventory
adjustments.
General
Trends and Outlook
We expect our business to continue to be affected by the
following key trends. Our expectations are based on assumptions
made by us and information currently available to us. To the
extent our underlying assumptions about or interpretations of
available information prove to be incorrect, our actual results
may vary materially from our expected results.
Commodity Prices In the fourth
quarter of 2008, natural gas, NGL and crude oil prices dropped
significantly compared to prices in 2007 and the first three
quarters of 2008. We are continuing to experience relatively
lower commodity prices in 2009. Commodity prices are impacted by
demand, which has been negatively impacted by the current
recessionary environment.
Natural Gas Supply and Outlook
In the near term, softening of
natural gas prices, reduced demand for natural gas and NGLs,
potential reduction in available capital, and the recent
downturn in the economy have had a moderating effect on levels
of drilling activity. The impact of these factors will vary
across our broad geographic locations. Generally, we expect a
decrease in drilling levels in 2009. The number of active oil
and gas rigs drilling in the United States was 364 and 1,347,
respectively, at December 31, 2008, compared to 325 and
1,452, respectively, at December 31, 2007. Our long-term
view is that natural gas prices will return to a level that
would support the relatively higher levels of natural
gas-related drilling experienced in recent years in the United
States, as producers seek to increase their level of natural gas
production. We believe that in the long-term an increase in
United States drilling activity, additional sources of supply
such as liquefied natural gas, and imports of natural gas will
be required for the natural gas industry to meet the expected
increased demand for natural gas in the United States.
60
Additionally, the capacity on certain downstream NGL and natural
gas infrastructure has tightened recently and can be further
constrained seasonally or when there is severe weather.
Constrained market outlets may restrict us from operating our
facilities optimally.
Processing Margins Except for
our fee-based contracts, our processing profitability is
dependent upon pricing and market demand for natural gas, NGLs
and condensate, which are beyond our control and have been
volatile. We have mitigated our cash flow exposure to commodity
price movements for these commodities by entering into
derivative arrangements through 2013 for a significant portion
of our currently anticipated natural gas, NGL and condensate
commodity price risk associated with the equity volumes from our
gathering and processing operations. For additional information
regarding our derivative activities, please read
Quantitative and Qualitative Disclosures about
Market Risk Commodity Price Risk
Commodity Cash Flow Protection Activities.
Wholesale Propane Supply and Outlook
We are a wholesale supplier of propane for
the midwest and northeastern United States, which consists of
Connecticut, Maine, Massachusetts, New Hampshire, New York,
Ohio, Pennsylvania, Rhode Island and Vermont. Pipeline
deliveries to this region in the winter season are generally at
capacity and competing propane supply sources, generally
consisting of open access propane terminals supplied by
interstate pipelines, can have significant supply constraints or
outages during peak market conditions. Due to our multiple
propane supply sources, propane supply contractual arrangements,
significant storage capabilities, and multiple terminal
locations for wholesale propane delivery, we are generally able
to provide our retail propane distribution customers with
reliable supplies of propane during periods of tight supply,
such as the winter months when their retail customers consume
the most propane for home heating.
Competition The natural gas
services business is highly competitive in our markets and
includes major integrated oil and gas companies, interstate and
intrastate pipelines, and companies that gather, compress,
treat, process, transport
and/or
market natural gas. Competition is often the greatest in
geographic areas experiencing robust drilling by producers and
during periods of high commodity prices for crude oil, natural
gas and/or
natural gas liquids. Competition is also increased in those
geographic areas where our commercial contracts with our
customers are shorter in length of term and therefore must be
renegotiated on a more frequent basis.
The wholesale propane business is highly competitive in the
upper midwest and northeastern regions of the United States. Our
wholesale propane business competitors include major
integrated oil and gas and energy companies, and interstate and
intrastate pipelines.
Impact of Inflation Our
industry has experienced rising inflation due to increased
activity in the energy sector. Consequently, our costs for
chemicals, utilities, materials and supplies, contract labor and
major equipment purchases have increased. Recently however, we
have seen softening in certain costs. In the future, we may
again be affected by inflation. To the extent permitted by
competition, regulation and our existing agreements, we have and
will continue to pass along increased costs to our customers in
the form of higher fees.
2009
Outlook
Our focus in 2009 will be on the basics of the business,
including operating our assets well, being disciplined with all
uses of funds and effectively managing our business risk and
daily operations in a very uncertain and volatile business
environment.
The restoration of our operations is nearing completion. Repairs
to the Discovery system, which was damaged by the hurricanes in
fall 2008, were substantially completed in January 2009.
Approximately 85% of the volumes and margins have been returned
to service, with the remainder expected by early March. The
Discovery distribution is paid one quarter in arrears. We do not
expect to receive a distribution from Discovery during the first
quarter of 2009. We would expect to receive a distribution
during the second quarter of 2009, commensurate with the partial
restoration in January 2009, and a distribution during the third
quarter of 2009, commensurate with the return to full service.
The second phase of our Douglas pipeline integrity and system
enhancement project has been completed, returning over 80% of
the system volumes to service by mid-January 2009. The final
phase is on target for completion in March 2009.
61
We are in the process of returning gas online following the fire
caused by a third party pipeline rupture near our Carthage Hub,
and expect it to be returned to normal service by the end of
March 2009.
We will continue to execute on our two organic growth projects
in the Piceance Basin and East Texas. We expect the remaining
spending to be approximately $65.0 million in 2009, which
will be funded through our existing credit facility.
We expect to close the transaction with DCP Midstream, LLC in
April 2009 to acquire an additional 25.1% interest in East
Texas. We expect the transaction will be fully financed through
the issuance of 3.5 million Class D units issued to
DCP Midstream, LLC. The transaction is expected to generate cash
flow from operations of approximately $15.0 million over
the first twelve month period following the close of the
transaction. As a part of the transaction, DCP Midstream, LLC is
expected to provide a fixed price NGL derivative by component
for the first twelve month period following the close of the
transaction.
Cash flow assumptions for our 2009 outlook include a full year
impact from our Michigan acquisition, an increase in cash flows
during the second half of the year related to our Piceance Basin
and East Texas capital projects, and maintenance capital of
$10.0 million to $15.0 million, which includes the
remaining spending for the Douglas pipeline integrity and system
enhancement project. In total, we estimate the impact to cash
flow in 2009 as a result of operations disruptions at Discovery
and Douglas to be approximately $10.0 million to
$12.0 million.
Our cash flows are expected to vary under various commodity
price scenarios. However, the combination of our significant
fee-based business, our highly hedged position and minimum fees
in certain contracts provide downside protection to our cash
flows.
Our percentage of fee-based margins is expected to be
approximately 56% in 2009. We have hedged approximately 80% of
our equity position in natural gas liquids, condensate and
natural gas associated with the remainder of our expected
margins that are not fee-based.
Based upon our business plan, we expect that our available
capacity under our existing credit facility is sufficient to
support our operating needs and capital program in 2009.
Our
Operations
We manage our business and analyze and report our results of
operations on a segment basis. Our operations are divided into
our Natural Gas Services segment, our Wholesale Propane
Logistics segment and our NGL Logistics segment.
Natural
Gas Services Segment
Results of operations from our Natural Gas Services segment are
determined primarily by the volumes of natural gas gathered,
compressed, treated, processed, transported and sold through our
gathering, processing and pipeline systems; the volumes of NGLs
and condensate sold; and the level of our realized natural gas,
NGL and condensate prices. We generate our revenues and our
gross margin for our Natural Gas Services segment principally
from contracts that contain a combination of the following
arrangements:
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Fee-based arrangements Under fee-based
arrangements, we receive a fee or fees for one or more of the
following services: gathering, compressing, treating, processing
or transporting natural gas; and transporting NGLs. Our
fee-based arrangements include natural gas purchase arrangements
pursuant to which we purchase natural gas at the wellhead or
other receipt points, at an index related price at the delivery
point less a specified amount, generally the same as the
transportation fees we would otherwise charge for transportation
of natural gas from the wellhead location to the delivery point.
The revenues we earn are directly related to the volume of
natural gas or NGLs that flows through our systems and are not
directly dependent on commodity prices. However, to the extent a
sustained decline in commodity prices results in a decline in
volumes, our revenues from these arrangements would be reduced.
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Percent-of-proceeds Under percent-of-proceeds
arrangements, we generally purchase natural gas from producers
at the wellhead, or other receipt points, gather the wellhead
natural gas through our gathering system, treat and process the
natural gas, and then sell the resulting residue natural gas and
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62
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NGLs based on index prices from published index market prices.
We remit to the producers either an
agreed-upon
percentage of the actual proceeds that we receive from our sales
of the residue natural gas and NGLs, or an
agreed-upon
percentage of the proceeds based on index related prices for the
natural gas and the NGLs, regardless of the actual amount of the
sales proceeds we receive. Certain of these arrangements may
also result in our returning all or a portion of the residue
natural gas
and/or the
NGLs to the producer, in lieu of returning sales proceeds. Our
revenues under percent-of-proceeds arrangements correlate
directly with the price of natural gas
and/or NGLs.
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In addition to the above contract types, our equity method
investments also generate equity earnings for our Natural Gas
Services segment under keep-whole arrangements. Under the terms
of a keep-whole processing contract, we gather natural gas from
the producer for processing, sell the NGLs and return to the
producer residue natural gas with a Btu content equivalent to
the Btu content of the natural gas gathered. This arrangement
keeps the producer whole to the thermal value of the natural gas
received. Under this type of contract, we are exposed to the
frac spread. The frac spread is the difference between the value
of the NGLs extracted from processing and the value of the Btu
equivalent of the residue natural gas. We benefit in periods
when NGL prices are higher relative to natural gas prices when
that frac spread exceeds the operating costs of our equity
method investments. Fluctuations in commodity prices are
expected to continue to impact the operating costs of these
entities.
We have mitigated a significant portion of our anticipated
natural gas, NGL and condensate commodity price risk associated
with the equity volumes from our gathering and processing
operations through 2013 with fixed price natural gas and crude
oil swaps. With these swaps, we expect our cash flow exposure to
commodity price movements to be reduced. For additional
information regarding our derivative activities, please read
Quantitative and Qualitative Disclosures about
Market Risk Commodity Price Risk
Commodity Cash Flow Protection Activities.
Effective July 1, 2007, we elected to discontinue using the
hedge method of accounting for our commodity cash flow hedges.
We are using the mark-to-market method of accounting for all
commodity derivative financial instruments, which has
significantly increased the volatility of our results of
operations as we recognize, in current earnings, all non-cash
gains and losses from the mark-to-market on non-trading
derivative activity.
The natural gas supply for our gathering pipelines and
processing plants is derived primarily from natural gas wells
located in Colorado, Louisiana, Michigan, Oklahoma, Texas,
Wyoming and the Gulf of Mexico. The Pelico system also receives
natural gas produced in Texas through its interconnect with
other pipelines that transport natural gas from Texas into
western Louisiana. These areas have experienced significant
levels of drilling activity, providing us with opportunities to
access newly developed natural gas supplies. We identify primary
suppliers as those individually representing 10% or more of our
total natural gas supply. Our two primary suppliers of natural
gas in our Natural Gas Services segment represented
approximately 30% of the
499 MMcf/d
of natural gas supplied to this system in 2008. We actively seek
new supplies of natural gas, both to offset natural declines in
the production from connected wells and to increase throughput
volume. We obtain new natural gas supplies in our operating
areas by contracting for production from new wells, connecting
new wells drilled on dedicated acreage, or by obtaining natural
gas that has been directly received or released from other
gathering systems.
We sell natural gas to marketing affiliates of natural gas
pipelines, marketing affiliates of integrated oil companies,
marketing affiliates of DCP Midstream, LLC, national wholesale
marketers, industrial end-users and gas-fired power plants. We
typically sell natural gas under market index related pricing
terms. The NGLs extracted from the natural gas at our processing
plants are sold at market index prices to DCP Midstream, LLC or
its affiliates, or to third parties. In addition, under our
merchant arrangements, we use a subsidiary of DCP Midstream, LLC
as our agent to purchase natural gas from third parties at
pipeline interconnect points, as well as residue gas from our
Minden and Ada processing plants, and then resell the aggregated
natural gas to third parties. We also have entered into a
contractual arrangement with a subsidiary of DCP Midstream, LLC
that requires DCP Midstream, LLC to supply Pelicos system
requirements that exceed its on-system supply. Accordingly, DCP
Midstream, LLC purchases natural gas and transports it to our
Pelico system, where
63
we buy the gas from DCP Midstream, LLC at the actual acquisition
cost plus transportation service charges incurred. If our Pelico
system has volumes in excess of the on-system demand, DCP
Midstream, LLC will purchase the excess natural gas from us and
transport it to sales points at an index based price less a
contractually agreed to marketing fee. In addition, DCP
Midstream, LLC may purchase other excess natural gas volumes at
certain Pelico outlets for a price that equals the original
Pelico purchase price from DCP Midstream, LLC plus a portion of
the index differential between upstream sources to certain
downstream indices with a maximum differential and a minimum
differential plus a fixed fuel charge and other related
adjustments. To the extent possible, we match the pricing of our
supply portfolio to our sales portfolio in order to lock in
value and reduce our overall commodity price risk. We manage the
commodity price risk of our supply portfolio and sales portfolio
with both physical and financial transactions. As a service to
our customers, we may enter into physical fixed price natural
gas purchases and sales, utilizing financial derivatives to swap
this fixed price risk back to market index. We may enter into
financial derivatives to lock in price differentials across the
Pelico system to maximize the value of pipeline capacity. These
financial derivatives are accounted for using mark-to-market
accounting. We also gather, process and transport natural gas
under fee-based transportation contracts.
Wholesale
Propane Logistics Segment
We operate a wholesale propane logistics business in the midwest
and northeastern United States. We purchase large volumes of
propane supply from natural gas processing plants and
fractionation facilities, and crude oil refineries, primarily
located in the Texas and Louisiana Gulf Coast area, Canada and
other international sources, and transport these volumes of
propane supply by pipeline, rail or ship to our terminals and
storage facilities in the Midwest and the northeastern areas of
the United States. We identify primary suppliers as those
individually representing 10% or more of our total propane
supply. Our three primary suppliers of propane, two of which are
affiliated entities, represented approximately 82% of our
propane supplied in 2008. We sell propane on a wholesale basis
to retail propane distributors who in turn resell propane to
their retail customers.
Due to our multiple propane supply sources, annual and long-term
propane supply purchase arrangements, significant storage
capabilities, and multiple terminal locations for wholesale
propane delivery, we are generally able to provide our retail
propane distribution customers with reliable supplies of propane
during periods of tight supply, such as the winter months when
their retail customers generally consume the most propane for
home heating. In particular, we generally offer our customers
the ability to obtain propane supply volumes from us in the
winter months that are generally significantly greater than
their purchase of propane from us in the summer. We believe
these factors generally allow us to maintain our generally
favorable relationship with our customers.
We manage our wholesale propane margins by selling propane to
retail propane distributors under annual sales agreements
negotiated each spring that specify floating price terms that
provide us a margin in excess of our floating index-based supply
costs under our supply purchase arrangements. In the event that
a retail propane distributor desires to purchase propane from us
on a fixed price basis, we sometimes enter into fixed price
sales agreements with terms of up to one year, and we manage
this commodity price risk by entering into either offsetting
physical purchase agreements or financial derivative
instruments, with either DCP Midstream, LLC or third parties,
that typically match the quantities of propane subject to these
fixed price sales agreements. Our portfolio of multiple supply
sources and storage capabilities allows us to actively manage
our propane supply purchases and to lower the aggregate cost of
supplies. Based on the carrying value of our inventory, timing
of inventory transactions and the volatility of the market value
of propane, we have historically and may continue to
periodically recognize non-cash lower of cost or market
inventory adjustments. In addition, we may use financial
derivatives to manage the value of our propane inventories.
NGL
Logistics Segment
Our pipelines provide transportation services for customers on a
fee basis. We have entered into contractual arrangements with
DCP Midstream, LLC that require DCP Midstream, LLC to pay us to
transport NGLs pursuant to a fee-based rate that is applied to
the volumes transported. Therefore, the results of
64
operations for this business segment are generally dependent
upon the volume of product transported and the level of fees
charged to customers. We do not take title to the products
transported on our NGL pipelines; rather, the shipper retains
title and the associated commodity price risk. For the Seabreeze
and Wilbreeze pipelines, we are responsible for any line loss or
gain in NGLs. For the Black Lake pipeline, any line loss or gain
in NGLs is allocated to the shipper. The volumes of NGLs
transported on our pipelines are dependent on the level of
production of NGLs from processing plants connected to our NGL
pipelines. When natural gas prices are high relative to NGL
prices, it is less profitable to process natural gas because of
the higher value of natural gas compared to the value of NGLs
and because of the increased cost of separating the NGLs from
the natural gas. As a result, we have experienced periods in the
past, and will likely experience periods in the future, in which
higher natural gas prices reduce the volume of NGLs extracted at
plants connected to our NGL pipelines and, in turn, lower the
NGL throughput on our assets. In the markets we serve, our
pipelines are the sole pipeline facility transporting NGLs from
the supply source.
How We
Evaluate Our Operations
Our management uses a variety of financial and operational
measurements to analyze our performance. These measurements
include the following: (1) volumes; (2) gross margin,
segment gross margin and adjusted segment gross margin;
(3) operating and maintenance expense, and general and
administrative expense; (4) EBITDA and adjusted EBITDA; and
(5) distributable cash flow. Gross margin, segment gross
margin, adjusted segment gross margin, EBITDA, adjusted EBITDA
and distributable cash flow measurements are not GAAP financial
measures. We provide reconciliations of certain non-GAAP
measures to their most directly comparable financial measures as
calculated and presented in accordance with GAAP. These non-GAAP
measures may not be comparable to a similarly titled measure of
another company because other entities may not calculate these
non-GAAP measures in the same manner.
Volumes We view throughput volumes for
our Natural Gas Services segment and our NGL Logistics segment,
and sales volumes for our Wholesale Propane Logistics segment as
important factors affecting our profitability. We gather and
transport some of the natural gas and NGLs under fee-based
transportation contracts. Revenue from these contracts is
derived by applying the rates stipulated to the volumes
transported. Pipeline throughput volumes from existing wells
connected to our pipelines will naturally decline over time as
wells deplete. Accordingly, to maintain or to increase
throughput levels on these pipelines and the utilization rate of
our natural gas processing plants, we must continually obtain
new supplies of natural gas and NGLs. Our ability to maintain
existing supplies of natural gas and NGLs and obtain new
supplies are impacted by: (1) the level of workovers or
recompletions of existing connected wells and successful
drilling activity in areas currently dedicated to our pipelines;
and (2) our ability to compete for volumes from successful
new wells in other areas. The throughput volumes of NGLs on our
pipelines are substantially dependent upon the quantities of
NGLs produced at our processing plants, as well as NGLs produced
at other processing plants that have pipeline connections with
our NGL pipelines. We regularly monitor producer activity in the
areas we serve and our pipelines, and pursue opportunities to
connect new supply to these pipelines.
Gross Margin, Segment Gross Margin and Adjusted Segment
Gross Margin We view our gross margin as an
important performance measure of the core profitability of our
operations. We review our gross margin monthly for consistency
and trend analysis.
We define gross margin as total operating revenues less
purchases of natural gas, propane and NGLs, and we define
segment gross margin for each segment as total operating
revenues for that segment less commodity purchases for that
segment. Our gross margin equals the sum of our segment gross
margins. We define adjusted segment gross margin as segment
gross margin plus non-cash derivative losses, less non-cash
derivative gains for that segment. Gross margin, segment gross
margin and adjusted segment gross margin are primary performance
measures used by management, as these measures represent the
results of product sales and purchases, a key component of our
operations. As an indicator of our operating performance, gross
margin, segment gross margin and adjusted segment gross margin
should not be considered an alternative to, or more meaningful
than, net income or loss, operating income, cash flows from
operating activities or any other measure of financial
performance presented in accordance with GAAP.
65
Our gross margin, segment gross margin and adjusted segment
gross margin may not be comparable to a similarly titled measure
of another company because other entities may not calculate
these measures in the same manner. The following table sets
forth our reconciliation of certain non-GAAP measures:
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Year Ended December 31,
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Reconciliation of Non-GAAP Measures
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2008
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2007
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2006
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(Millions)
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Reconciliation of net income (loss) to gross margin:
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Net income (loss)
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$
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125.7
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$
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(15.8
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)
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$
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61.9
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Interest expense
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32.8
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25.8
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11.5
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Income tax expense
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0.1
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0.1
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Operating and maintenance expense
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43.0
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32.1
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23.7
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Depreciation and amortization expense
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36.5
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24.4
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12.8
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General and administrative expense
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24.0
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24.1
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21.0
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Other
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(1.5
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)
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Non-controlling interest in income
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3.9
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0.5
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Interest income
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(5.6
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)
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(5.3
|
)
|
|
|
(6.3
|
)
|
Earnings from equity method investments
|
|
|
(34.3
|
)
|
|
|
(39.3
|
)
|
|
|
(29.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
$
|
224.6
|
|
|
$
|
46.6
|
|
|
$
|
95.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment net income to segment gross
margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Services segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
170.2
|
|
|
$
|
11.6
|
|
|
$
|
79.6
|
|
Depreciation and amortization expense
|
|
|
33.8
|
|
|
|
21.9
|
|
|
|
11.1
|
|
Operating and maintenance expense
|
|
|
32.1
|
|
|
|
20.9
|
|
|
|
13.5
|
|
Non-controlling interest in income
|
|
|
3.9
|
|
|
|
0.5
|
|
|
|
|
|
Earnings from equity method investments
|
|
|
(33.5
|
)
|
|
|
(38.7
|
)
|
|
|
(28.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin
|
|
$
|
206.5
|
|
|
$
|
16.2
|
|
|
$
|
75.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash commodity derivative mark-to-market(a)
|
|
$
|
99.2
|
|
|
$
|
(78.3
|
)
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Propane Logistics segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
1.3
|
|
|
$
|
14.0
|
|
|
$
|
6.6
|
|
Depreciation and amortization expense
|
|
|
1.3
|
|
|
|
1.1
|
|
|
|
0.8
|
|
Operating and maintenance expense
|
|
|
9.9
|
|
|
|
10.4
|
|
|
|
8.6
|
|
Other
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin
|
|
$
|
11.0
|
|
|
$
|
25.5
|
|
|
$
|
16.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash commodity derivative mark-to-market(a)
|
|
$
|
2.4
|
|
|
$
|
(2.8
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Logistics segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
5.5
|
|
|
$
|
3.3
|
|
|
$
|
1.9
|
|
Depreciation and amortization expense
|
|
|
1.4
|
|
|
|
1.4
|
|
|
|
0.9
|
|
Operating and maintenance expense
|
|
|
1.0
|
|
|
|
0.8
|
|
|
|
1.6
|
|
Earnings from equity method investments
|
|
|
(0.8
|
)
|
|
|
(0.6
|
)
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin
|
|
$
|
7.1
|
|
|
$
|
4.9
|
|
|
$
|
4.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Non-cash commodity derivative mark-to-market is included in
segment gross margin, along with cash settlements for our
derivative contracts. |
66
Operating and Maintenance and General and Administrative
Expense Operating and maintenance expense
are costs associated with the operation of a specific asset.
Direct labor, ad valorem taxes, repairs and maintenance, lease
expenses, utilities and contract services comprise the most
significant portion of our operating and maintenance expense.
These expenses are relatively independent of the volumes through
our systems, but may fluctuate depending on the activities
performed during a specific period.
A substantial amount of our general and administrative expense
is incurred from DCP Midstream, LLC. We have entered into an
omnibus agreement, as amended, or the Omnibus Agreement, with
DCP Midstream, LLC. Under the Omnibus Agreement, we are required
to reimburse DCP Midstream, LLC for salaries of operating
personnel and employee benefits as well as capital expenditures,
maintenance and repair costs, taxes and other direct costs
incurred by DCP Midstream, LLC on our behalf. The fees under the
Omnibus Agreement increased $0.4 million per year effective
October 1, 2008, in connection with the acquisition of MPP.
We also pay DCP Midstream, LLC an annual fee under the Omnibus
Agreement for centralized corporate functions performed by DCP
Midstream, LLC on our behalf, including legal, accounting, cash
management, insurance administration and claims processing, risk
management, health, safety and environmental, information
technology, human resources, credit, payroll, taxes and
engineering. Under the Omnibus Agreement, DCP Midstream, LLC
provided parental guarantees, totaling $43.0 million at
December 31, 2008, to certain counterparties to our
commodity derivative instruments.
Our total general and administrative expense was comprised of
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Affiliate:
|
|
|
|
|
|
|
|
|
|
|
|
|
Omnibus Agreement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual fee
|
|
$
|
5.1
|
|
|
$
|
5.0
|
|
|
$
|
4.8
|
|
Wholesale propane logistics business
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
0.3
|
|
Southern Oklahoma
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
|
|
Discovery
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
|
|
Additional services
|
|
|
0.6
|
|
|
|
0.2
|
|
|
|
|
|
Momentum Energy Group, Inc.
|
|
|
1.6
|
|
|
|
0.5
|
|
|
|
|
|
Michigan Pipeline & Processing, LLC
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Omnibus Agreement
|
|
|
9.8
|
|
|
|
7.9
|
|
|
|
5.1
|
|
Other DCP Midstream, LLC
|
|
|
1.8
|
|
|
|
2.1
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total affiliate
|
|
|
11.6
|
|
|
|
10.0
|
|
|
|
8.1
|
|
Other
|
|
|
12.4
|
|
|
|
14.1
|
|
|
|
12.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
24.0
|
|
|
$
|
24.1
|
|
|
$
|
21.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Following is a summary of the fees we anticipate incurring in
2009 under the Omnibus Agreement and the effective date for
these fees:
|
|
|
|
|
|
|
Terms
|
|
Effective Date
|
|
Fee
|
|
|
|
|
|
(Millions)
|
|
|
Annual fee
|
|
2006
|
|
$
|
5.1
|
|
Wholesale propane logistics business
|
|
November 2006
|
|
|
2.0
|
|
Southern Oklahoma
|
|
May 2007
|
|
|
0.2
|
|
Discovery
|
|
July 2007
|
|
|
0.2
|
|
Additional services
|
|
August 2007
|
|
|
0.6
|
|
Momentum Energy Group, Inc.
|
|
August 2007
|
|
|
1.6
|
|
Michigan Pipeline & Processing, LLC
|
|
October 2008
|
|
|
0.4
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
10.1
|
|
|
|
|
|
|
|
|
67
The Omnibus Agreement also addresses the following matters:
|
|
|
|
|
DCP Midstream, LLCs obligation to indemnify us for certain
liabilities and our obligation to indemnify DCP Midstream, LLC
for certain liabilities;
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support for certain obligations related to derivative
financial instruments, such as commodity derivative instruments,
to the extent that such credit support arrangements were in
effect as of December 7, 2005 until the earlier of
December 7, 2010 or when we obtain certain credit ratings
from either Moodys Investor Services, Inc. or
Standard & Poors Ratings Group with respect to
any of our unsecured indebtedness; and
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support for our obligations related to commercial
contracts with respect to its business or operations that were
in effect at December 7, 2005 until the expiration of such
contracts.
|
All of the fees under the Omnibus Agreement will be adjusted
annually by the percentage change in the Consumer Price Index
for the applicable year. In addition, our general partner will
have the right to agree to further increases in connection with
expansions of our operations through the acquisition or
construction of new assets or businesses, with the concurrence
of the special committee of DCP Midstream GP, LLCs board
of directors.
Other general and administrative expenses paid to DCP Midstream,
LLC subsequent to our initial public offering include labor and
benefit costs related to accounting and internal audit
personnel, insurance as well as other administrative costs.
Additionally, DCP Midstream, LLC provided centralized corporate
functions on behalf of our predecessor operations, including
legal, accounting, cash management, insurance administration and
claims processing, risk management, health, safety and
environmental, information technology, human resources, credit,
payroll, internal audit, taxes and engineering. The
predecessors share of those costs was allocated based on
the predecessors proportionate net investment (consisting
of property, plant and equipment, net, equity method
investments, and intangible assets, net) as compared to DCP
Midstream, LLCs net investment. In managements
estimation, the allocation methodologies used were reasonable
and resulted in an allocation to the predecessors of their
respective costs of doing business, which were borne by DCP
Midstream, LLC.
We also incurred third party general and administrative
expenses, which were primarily related to compensation and
benefit expenses of the personnel who provide direct support to
our operations. Also included are expenses associated with
annual and quarterly reports to unitholders, tax return and
Schedule K-1
preparation and distribution, independent auditor fees, due
diligence and acquisition costs, costs associated with the
Sarbanes-Oxley Act of 2002, investor relations activities,
registrar and transfer agent fees, incremental director and
officer liability insurance costs, and director compensation.
EBITDA, Adjusted EBITDA and Distributable Cash Flow
We define EBITDA as net income or loss less
interest income, plus interest expense, income tax expense and
depreciation and amortization expense. We define adjusted EBITDA
as EBITDA plus non-cash commodity derivative losses, less
non-cash commodity derivative gains. EBITDA and adjusted EBITDA
are used as supplemental liquidity and performance measures by
our management and by external users of our financial
statements, such as investors, commercial banks, research
analysts and others, to assess:
|
|
|
|
|
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness, make cash
distributions to our unitholders and general partner, and
finance maintenance capital expenditures;
|
|
|
|
financial performance of our assets without regard to financing
methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
those of other companies in the midstream energy industry,
without regard to financing methods or capital
structure; and
|
|
|
|
viability of acquisitions and capital expenditure projects and
the overall rates of return on alternative investment
opportunities.
|
68
Our EBITDA and adjusted EBITDA may not be comparable to
similarly titled measures of another company because other
entities may not calculate these measures in the same manner. As
discussed in the Liquidity and Capital Resources section below,
our credit facility also defines EBITDA, which is used in
evaluating our compliance with our financial covenants.
EBITDA and adjusted EBITDA should not be considered an
alternative to, or more meaningful than, net income or loss,
operating income, cash flows from operating activities or any
other measure of financial performance presented in accordance
with GAAP as measures of operating performance, liquidity or
ability to service debt obligations. The following table sets
forth reconciliations of EBITDA from its most directly
comparable financial measures calculated in accordance with GAAP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Reconciliation of Non-GAAP Measures
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Reconciliation of net income (loss) to EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
Interest income
|
|
|
(5.6
|
)
|
|
|
(5.3
|
)
|
|
|
(6.3
|
)
|
Interest expense
|
|
|
32.8
|
|
|
|
25.8
|
|
|
|
11.5
|
|
Income tax expense
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
36.5
|
|
|
|
24.4
|
|
|
|
12.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
189.5
|
|
|
$
|
29.2
|
|
|
$
|
79.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of net cash provided by operating activities
to EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
101.5
|
|
|
$
|
65.4
|
|
|
$
|
94.8
|
|
Interest income
|
|
|
(5.6
|
)
|
|
|
(5.3
|
)
|
|
|
(6.3
|
)
|
Interest expense
|
|
|
32.8
|
|
|
|
25.8
|
|
|
|
11.5
|
|
Earnings from equity method investments, net of distributions
|
|
|
(25.6
|
)
|
|
|
0.4
|
|
|
|
3.3
|
|
Income tax expense
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
|
|
Net changes in operating assets and liabilities
|
|
|
89.8
|
|
|
|
(56.9
|
)
|
|
|
(25.8
|
)
|
Other, net
|
|
|
(3.5
|
)
|
|
|
(0.3
|
)
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
189.5
|
|
|
$
|
29.2
|
|
|
$
|
79.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We define distributable cash flow as net cash provided by or
used in operating activities, less maintenance capital
expenditures, net of reimbursable projects, plus or minus
adjustments for non-cash mark-to-market of derivative
instruments, proceeds from divestiture of assets,
non-controlling interest on depreciation, net changes in
operating assets and liabilities, and other adjustments to
reconcile net cash provided by or used in operating activities
(see Liquidity and Capital Resources for
further definition of maintenance capital expenditures).
Maintenance capital expenditures are capital expenditures made
where we add on to or improve capital assets owned, or acquire
or construct new capital assets, if such expenditures are made
to maintain, including over the long term, our operating
capacity or revenues. Non-cash mark-to-market of derivative
instruments is considered to be non-cash for the purpose of
computing distributable cash flow because settlement will not
occur until future periods, and will be impacted by future
changes in commodity prices. Distributable cash flow is used as
a supplemental liquidity measure by our management and by
external users of our financial statements, such as investors,
commercial banks, research analysts and others, to assess our
ability to make cash distributions to our unitholders and our
general partner. Our distributable cash flow may not be
comparable to a similarly titled measure of another company
because other entities may not calculate distributable cash flow
in the same manner.
69
Critical
Accounting Policies and Estimates
Our financial statements reflect the selection and application
of accounting policies that require management to make estimates
and assumptions. We believe that the following are the more
critical judgment areas in the application of our accounting
policies that currently affect our financial condition and
results of operations. These accounting policies are described
further in Note 2 of the Notes to Consolidated Financial
Statements in Item 8. Financial Statements and
Supplementary Data.
|
|
|
|
|
|
|
|
|
Effect if Actual Results Differ from
|
Description
|
|
Judgments and Uncertainties
|
|
Assumptions
|
|
Inventories
|
|
|
|
|
Inventories, which consist primarily of propane, are recorded at
the lower of weighted-average cost or market value.
|
|
Judgment is required in determining the market value of
inventory, as the geographic location impacts market prices, and
quoted market prices may not be available for the particular
location of our inventory.
|
|
If the market value of our inventory is lower than the cost, we
may be exposed to losses that could be material. If propane
prices were to decrease by 10% below our December 31, 2008
weighted-average cost, our net income would be affected by
approximately $2.1 million.
|
Goodwill
|
|
|
|
|
Goodwill is the cost of an acquisition less the fair value of
the net assets of the acquired business. We evaluate goodwill
for impairment annually in the third quarter, and whenever
events or changes in circumstances indicate it is more likely
than not that the fair value of a reporting unit is less than
its carrying amount.
|
|
We determine fair value using widely accepted valuation
techniques, namely discounted cash flow and market multiple
analyses. These techniques are also used when allocating the
purchase price to acquired assets and liabilities. These types
of analyses require us to make assumptions and estimates
regarding industry and economic factors and the profitability of
future business strategies. It is our policy to conduct
impairment testing based on our current business strategy in
light of present industry and economic conditions, as well as
future expectations.
|
|
We completed our impairment testing of goodwill using the
methodology described herein, and determined there was no
impairment. We have not recorded goodwill impairment during the
year ended December 31, 2008. The carrying value of goodwill as
of December 31, 2008 was $88.8 million.
|
Impairment of Long-Lived Assets
|
|
|
|
|
We periodically evaluate whether the carrying value of
long-lived assets has been impaired when circumstances indicate
the carrying value of those assets may not be recoverable. This
evaluation is based on undiscounted cash flow projections
expected to be realized over the remaining useful life of the
primary asset. The carrying amount is not recoverable if it
exceeds the sum of undiscounted cash flows expected to result
from the use and eventual disposition of the asset. If the
carrying value is not recoverable, the impairment loss is
measured as the excess of the assets carrying value over
its fair value.
|
|
Our impairment analyses may require management to apply judgment
in estimating future cash flows as well as asset fair values,
including forecasting useful lives of the assets, assessing the
probability of different outcomes, and selecting the discount
rate that reflects the risk inherent in future cash flows. We
assess the fair value of long-lived assets using commonly
accepted techniques, and may use more than one method,
including, but not limited to, recent third party comparable
sales and discounted cash flow models. These techniques are also
used when allocating the purchase price to acquired assets and
liabilities.
|
|
Using the impairment review methodology described herein, we
have not recorded impairment charges during the year ended
December 31, 2008. If actual results are not consistent with our
assumptions and estimates or our assumptions and estimates
change due to new information, we may be exposed to an
impairment charge. The carrying value of our long-lived assets
as of December 31, 2008 was $677.0 million.
|
70
|
|
|
|
|
|
|
|
|
Effect if Actual Results Differ from
|
Description
|
|
Judgments and Uncertainties
|
|
Assumptions
|
|
Impairment of Equity Method Investments
|
We evaluate our equity method investments for impairment
whenever events or changes in circumstances indicate, in
managements judgment, that the carrying value of such
investment may have experienced a decline in value. When
evidence of loss in value has occurred, we compare the estimated
fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred.
|
|
Our impairment loss calculations require management to apply
judgment in estimating future cash flows and asset fair values,
including forecasting useful lives of the assets, assessing the
probability of differing estimated outcomes, and selecting the
discount rate that reflects the risk inherent in future cash
flows. We assess the fair value of our equity method investments
using commonly accepted techniques, and may use more than one
method, including, but not limited to, recent third party
comparable sales and discounted cash flow models.
|
|
Using the impairment review methodology described herein, we
have not recorded impairment charges during the year ended
December 31, 2008. If the estimated fair value of our equity
method investments is less than the carrying value, we would
recognize an impairment loss for the excess of the carrying
value over the estimated fair value. The carrying value of our
equity method investments as of December 31, 2008 was $175.4
million.
|
Accounting for Risk Management Activities and Financial
Instruments
|
Each derivative not qualifying for the normal purchases and
normal sales exception is recorded on a gross basis in the
consolidated balance sheets at its fair value as unrealized
gains or unrealized losses on derivative instruments. Derivative
assets and liabilities remain classified in our consolidated
balance sheets as unrealized gains or unrealized losses on
derivative instruments at fair value until the contractual
settlement period impacts earnings. Values are adjusted to
reflect the credit risk inherent in the transaction as well as
the potential impact of liquidating open positions in an orderly
manner over a reasonable time period under current conditions.
|
|
When available, quoted market prices or prices obtained through
external sources are used to determine a contracts fair
value. For contracts with a delivery location or duration for
which quoted market prices are not available, fair value is
determined based on pricing models developed primarily from
historical and expected correlations with quoted market prices.
|
|
If our estimates of fair value are inaccurate, we may be exposed
to losses or gains that could be material. A 10% difference in
our estimated fair value of derivatives at December 31, 2008
would have affected net income by approximately $2.0 million for
the year ended December 31, 2008.
|
Accounting for Equity-Based Compensation
|
Our long-term incentive plan permits for the grant of restricted
units, phantom units, unit options and substitute awards.
Equity-based compensation expense is recognized over the vesting
period or service period of the related awards. We estimate the
fair value of each award, and the number of awards that will
ultimately vest, at the end of each period.
|
|
Estimating the fair value of each award, the number of awards
that will ultimately vest, and the forfeiture rate requires
management to apply judgment to estimate the tenure of our
employees and the achievement of certain performance targets
over the performance period.
|
|
If actual results are not consistent with our assumptions and
judgments or our assumptions and estimates change due to new
information, we may experience material changes in compensation
expense.
|
71
|
|
|
|
|
|
|
|
|
Effect if Actual Results Differ from
|
Description
|
|
Judgments and Uncertainties
|
|
Assumptions
|
|
Accounting for Asset Retirement Obligations
|
Asset retirement obligations associated with tangible long-lived
assets are recorded at fair value in the period in which they
are incurred, if a reasonable estimate of fair value can be
made, and added to the carrying amount of the associated asset.
This additional carrying amount is then depreciated over the
life of the asset. The liability is determined using a credit
adjusted risk free interest rate, and increases due to the
passage of time based on the time value of money until the
obligation is settled.
|
|
Estimating the fair value of asset retirement obligations
requires management to apply judgment to evaluate the necessary
retirement activities, estimate the costs to perform those
activities, including the timing and duration of potential
future retirement activities, and estimate the risk free
interest rate. When making these assumptions, we consider a
number of factors, including historical retirement costs, the
location and complexity of the asset and general economic
conditions.
|
|
If actual results are not consistent with our assumptions and
judgments or our assumptions and estimates change due to new
information, we may experience material changes in our asset
retirement obligations. Establishing an asset retirement
obligation has no initial impact on net income. A 10% change in
depreciation and accretion expense associated with our asset
retirement obligations during the year ended December 31, 2008,
would not have had a significant effect on net income.
|
72
Results
of Operations
Consolidated
Overview
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2008. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variance
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007
|
|
|
2007 vs. 2006
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
2008(a)
|
|
|
2007(a)
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
|
(Millions, except as indicated)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Services(b)
|
|
$
|
791.5
|
|
|
$
|
404.1
|
|
|
$
|
415.3
|
|
|
$
|
387.4
|
|
|
|
96
|
%
|
|
$
|
(11.2
|
)
|
|
|
(3
|
)%
|
Wholesale Propane Logistics
|
|
|
483.0
|
|
|
|
459.6
|
|
|
|
375.2
|
|
|
|
23.4
|
|
|
|
5
|
%
|
|
|
84.4
|
|
|
|
23
|
%
|
NGL Logistics
|
|
|
11.3
|
|
|
|
9.6
|
|
|
|
5.3
|
|
|
|
1.7
|
|
|
|
18
|
%
|
|
|
4.3
|
|
|
|
81
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,285.8
|
|
|
|
873.3
|
|
|
|
795.8
|
|
|
|
412.5
|
|
|
|
47
|
%
|
|
|
77.5
|
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin(c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Services
|
|
|
206.5
|
|
|
|
16.2
|
|
|
|
75.3
|
|
|
|
190.3
|
|
|
|
1,175
|
%
|
|
|
(59.1
|
)
|
|
|
(78
|
)%
|
Wholesale Propane Logistics
|
|
|
11.0
|
|
|
|
25.5
|
|
|
|
16.0
|
|
|
|
(14.5
|
)
|
|
|
(57
|
)%
|
|
|
9.5
|
|
|
|
59
|
%
|
NGL Logistics
|
|
|
7.1
|
|
|
|
4.9
|
|
|
|
4.1
|
|
|
|
2.2
|
|
|
|
45
|
%
|
|
|
0.8
|
|
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin
|
|
|
224.6
|
|
|
|
46.6
|
|
|
|
95.4
|
|
|
|
178.0
|
|
|
|
382
|
%
|
|
|
(48.8
|
)
|
|
|
(51
|
)%
|
Operating and maintenance expense
|
|
|
(43.0
|
)
|
|
|
(32.1
|
)
|
|
|
(23.7
|
)
|
|
|
10.9
|
|
|
|
34
|
%
|
|
|
8.4
|
|
|
|
35
|
%
|
General and administrative expense
|
|
|
(24.0
|
)
|
|
|
(24.1
|
)
|
|
|
(21.0
|
)
|
|
|
(0.1
|
)
|
|
|
|
%
|
|
|
3.1
|
|
|
|
15
|
%
|
Other
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
1.5
|
|
|
|
*
|
|
|
|
|
|
|
|
|
%
|
Earnings from equity method investments(d)
|
|
|
34.3
|
|
|
|
39.3
|
|
|
|
29.2
|
|
|
|
(5.0
|
)
|
|
|
(13
|
)%
|
|
|
10.1
|
|
|
|
35
|
%
|
Non-controlling interest in income
|
|
|
(3.9
|
)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
3.4
|
|
|
|
680
|
%
|
|
|
0.5
|
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(e)
|
|
|
189.5
|
|
|
|
29.2
|
|
|
|
79.9
|
|
|
|
160.3
|
|
|
|
549
|
%
|
|
|
(50.7
|
)
|
|
|
(64
|
)%
|
Depreciation and amortization expense
|
|
|
(36.5
|
)
|
|
|
(24.4
|
)
|
|
|
(12.8
|
)
|
|
|
12.1
|
|
|
|
50
|
%
|
|
|
11.6
|
|
|
|
91
|
%
|
Interest income
|
|
|
5.6
|
|
|
|
5.3
|
|
|
|
6.3
|
|
|
|
0.3
|
|
|
|
6
|
%
|
|
|
(1.0
|
)
|
|
|
16
|
%
|
Interest expense
|
|
|
(32.8
|
)
|
|
|
(25.8
|
)
|
|
|
(11.5
|
)
|
|
|
7.0
|
|
|
|
27
|
%
|
|
|
14.3
|
|
|
|
*
|
|
Income tax expense
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
0.1
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
|
$
|
141.5
|
|
|
|
*
|
|
|
$
|
(77.7
|
)
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas throughput
(MMcf/d)(d)
|
|
|
838
|
|
|
|
756
|
|
|
|
666
|
|
|
|
82
|
|
|
|
11
|
%
|
|
|
90
|
|
|
|
14
|
%
|
NGL gross production (Bbls/d)(d)
|
|
|
20,659
|
|
|
|
22,122
|
|
|
|
19,485
|
|
|
|
(1,463
|
)
|
|
|
(7
|
)%
|
|
|
2,637
|
|
|
|
14
|
%
|
Propane sales volume (Bbls/d)
|
|
|
21,053
|
|
|
|
22,798
|
|
|
|
21,259
|
|
|
|
(1,745
|
)
|
|
|
(8
|
)%
|
|
|
1,539
|
|
|
|
7
|
%
|
NGL pipelines throughput (Bbls/d)(d)
|
|
|
31,407
|
|
|
|
28,961
|
|
|
|
25,040
|
|
|
|
2,446
|
|
|
|
8
|
%
|
|
|
3,921
|
|
|
|
16
|
%
|
|
|
|
* |
|
Percentage change is not meaningful. |
|
(a) |
|
Includes the results from the Michigan Pipeline &
Processing, LLC, or MPP, Momentum Energy Group, Inc, or MEG, and
Southern Oklahoma acquisitions, from their respective
acquisition dates of October 2008, August 2007 and May 2007. |
|
(b) |
|
Includes the effect of the acquisition of the Swap entered into
by DCP Midstream, LLC in March 2007. The Swap was for a total of
approximately 1.9 million barrels at $66.72 per barrel. |
73
|
|
|
(c) |
|
Gross margin consists of total operating revenues, including
commodity derivative activity, less purchases of natural gas,
propane and NGLs, and segment gross margin for each segment
consists of total operating revenues for that segment, less
commodity purchases for that segment. Please read How We
Evaluate Our Operations above. |
|
(d) |
|
Includes our proportionate share of the throughput volumes and
earnings of Black Lake, East Texas and Discovery for all periods
presented. Earnings for Discovery and Black Lake include the
amortization of the net difference between the carrying amount
of the investments and the underlying equity of the investments. |
|
(e) |
|
EBITDA consists of net income or loss less interest income plus
interest expense, income tax expense, and depreciation and
amortization expense. Please read How We Evaluate Our
Operations above. |
Year
Ended December 31, 2008 vs. Year Ended December 31,
2007
Total Operating Revenues Total operating
revenues increased in 2008 compared to 2007, primarily due to
the following:
|
|
|
|
|
$213.7 million increase primarily attributable to increased
commodity prices as well as higher natural gas, NGL and
condensate sales volumes, primarily as a result of the MEG, MPP
and Southern Oklahoma acquisitions, partially offset by
decreased volumes due to the impact of hurricanes, for our
Natural Gas Services segment;
|
|
|
|
$156.8 million increase related to commodity derivative
activity, resulting from the following:
|
|
|
|
|
|
we had a gain of $72.3 million in 2008 and a loss of
$87.6 million in 2007, resulting in an increase of
$159.9 million, which is included in gains (losses) from
commodity derivative activity. This increase includes an
increase in unrealized gains of $184.1 million due to
forward prices of commodities generally being lower at the end
of the year 2008 compared to 2007. Offsetting this increase in
gain was an increase in realized cash settlement losses of
$24.2 million due to average prices of commodities
generally being higher for the year ended December 31, 2008
compared to 2007; and
|
|
|
|
we had a $3.1 million increase in unrealized loss, which is
included in sales of natural gas, NGLs and condensate;
|
|
|
|
|
|
$22.1 million increase in transportation processing and
other revenue, primarily attributable to the MEG and MPP
acquisitions in our Natural Gas Services segment;
|
|
|
|
$19.0 million increase attributable to higher propane
prices offset by decreased propane sales volumes as a result of
lower demand for our Wholesale Propane Logistics
segment; and
|
|
|
|
$0.9 million increase due to increased throughput volumes,
transportation, processing and other revenue, and increases
related to settlement of pipeline imbalances in our NGL
logistics segment.
|
Gross Margin Gross margin increased in 2008
compared to 2007, primarily due to the following:
|
|
|
|
|
$190.3 million increase for our Natural Gas Services
segment primarily due to increases related to commodity
derivative activity, an increase in natural gas, NGL and
condensate production, mainly as a result of the MEG, MPP and
Southern Oklahoma acquisitions, partially offset by decreased
volumes due to the impact of hurricanes; and
|
|
|
|
$2.2 million increase for our NGL Logistics segment
primarily attributable to increases related to settlement of
pipeline imbalances and increased throughput volumes; partially
offset by
|
|
|
|
$14.5 million decrease for our Wholesale Propane Logistics
segment as a result of increased non-cash lower of cost or
market inventory adjustments due to a decline in propane prices
in the second half of 2008. We estimate that approximately half
of the 2008 write downs were recovered through the sale of
inventory in 2008. We also had lower per unit margins and
propane sales volumes, partially offset by commodity derivative
activity.
|
74
Operating and Maintenance Expense Operating
and maintenance expense increased in 2008 compared to 2007,
primarily as a result of the MEG, MPP and Southern Oklahoma
acquisitions in our Natural Gas Services segment, partially
offset by decreased property taxes in our Wholesale Propane
Logistics segment.
General and Administrative Expense General
and administrative expense decreased in 2008 compared to 2007,
primarily due to acquisition-related costs incurred in 2007 and
decreased compensation and benefits in 2008, partially offset by
increased legal expenses in 2008.
Earnings from Equity Method Investments
Earnings from equity method investments decreased in 2008
compared to 2007, primarily due to decreased equity earnings of
$6.7 million from Discovery due primarily to hurricanes, as
discussed in the Natural Gas Services Segment section below,
partially offset by increased equity earnings of
$1.5 million from East Texas and $0.2 million from
Black Lake.
Non-Controlling Interest in Income
Non-controlling interest in income reduced income by
$3.9 million and $0.5 million in 2008 and 2007,
respectively, and represents the non-controlling interest
holders portion of the net income of our Collbran Valley
Gas Gathering system joint venture, acquired in the MEG
acquisition and in 2008 also includes the non-controlling
interest holders portion of the net income of Jackson
Pipeline Company, acquired in the MPP acquisition.
Depreciation and Amortization Expense
Depreciation and amortization expense increased in 2008 compared
to 2007, primarily as a result of acquisitions.
Interest Expense Interest expense increased
in 2008 compared to 2007, primarily as a result of financing
acquisitions, partially offset by lower average interest rates.
Year
Ended December 31, 2007 vs. Year Ended December 31,
2006
Total Operating Revenues Total operating
revenues increased in 2007 compared to 2006, primarily due to
the following:
|
|
|
|
|
$88.1 million increase attributable to higher propane
prices and higher sales volumes for our Wholesale Propane
Logistics segment;
|
|
|
|
$66.2 million increase primarily attributable to an
increase in natural gas, NGL and condensate sales volumes,
including increases as a result of the MEG and Southern Oklahoma
acquisitions, and increases in NGL and condensate prices,
partially offset by a decrease in natural gas sales volumes,
primarily as a result of an amendment to a contract with an
affiliate in 2006, which resulted in a prospective change in the
reporting of certain Pelico revenues from a gross presentation
to a net presentation for our Natural Gas Services segment;
|
|
|
|
$7.3 million increase in transportation processing and
other revenue primarily attributable to an increase in
throughput volumes in our Natural Gas Services segment; and
|
|
|
|
$3.4 million increase due to changes in product mix and
increased volumes for our NGL Logistics segment; offset by
|
|
|
|
$87.5 million decrease related to commodity derivative
activity, an increase of $0.2 million which is included in
sales of natural gas, NGLs and condensate, and a decrease of
$87.7 million which is included in losses from derivative
activity.
|
Gross Margin Gross margin decreased in 2007
compared to 2006, primarily due to the following:
|
|
|
|
|
$59.1 million decrease for our Natural Gas Services segment
primarily due to decreases related to commodity derivative
activity, and a decrease in marketing margins from the decline
in the differences of natural gas prices at various receipt and
delivery points across our Pelico system, offset by an increase
in NGL and condensate production, mainly as a result of the MEG
and Southern Oklahoma acquisitions, an increase in natural gas
throughput volumes and higher contractual fees charged to
customers; offset by
|
75
|
|
|
|
|
$9.5 million increase for our Wholesale Propane Logistics
segment due to higher per unit margins as a result of changes in
contract mix and the ability to capture lower priced supply
sources, decreased non-cash lower of cost or market inventory
adjustments recognized in 2007, and higher sales volumes
primarily due to the completion of the Midland terminal, which
became operational in May 2007, partially offset by a decrease
related to commodity derivative activity; and
|
|
|
|
$0.8 million increase for our NGL Logistics segment
primarily attributable to changes in product mix and increased
volumes, as well as increased transportation processing and
other revenue.
|
Operating and Maintenance Expense Operating
and maintenance expense increased in 2007 compared to 2006,
primarily as a result of the MEG and Southern Oklahoma
acquisitions, higher labor and benefits and pipeline integrity
costs in our Natural Gas Services segment, and higher operating
and maintenance expense at the Midland terminal, which became
operational in May 2007 in our Wholesale Propane Logistics
segment, offset by lower pipeline integrity costs on our
Seabreeze pipeline in our NGL Logistics segment.
General and Administrative Expense General
and administrative expense increased in 2007 compared to 2006,
primarily as a result of increased due diligence and acquisition
costs, increased fees under our omnibus agreement with DCP
Midstream, LLC and increased labor and benefit costs, partially
offset by decreases in audit and public company costs.
Earnings from Equity Method Investments
Earnings from equity method investments increased in 2007
compared to 2006, primarily due to increased equity earnings of
$7.2 million from Discovery, $2.6 million from East
Texas and $0.3 million from Black Lake.
Non-Controlling Interest in Income
Non-controlling interest in income reduced income by
$0.5 million in 2007, and represents the non-controlling
interest holders portion of the net income of our Collbran
Valley Gas Gathering system joint venture, acquired in the MEG
acquisition.
Depreciation and Amortization Expense
Depreciation and amortization expense increased in 2007 compared
to 2006, primarily as a result of acquisitions.
Interest Expense Interest expense increased
in 2007 compared to 2006, primarily as a result of financing the
2007 acquisitions.
76
Results
of Operations Natural Gas Services
Segment
This segment consists of our Northern Louisiana system, the
Southern Oklahoma system acquired in May 2007, a 25% limited
liability company interest in East Texas, a 40% limited
liability company interest in Discovery, and the Swap, acquired
in July 2007, our Colorado and Wyoming systems, acquired in
August 2007 and our Michigan systems, acquired in October 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variance
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007
|
|
|
2007 vs. 2006
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
2008(a)
|
|
|
2007(a)
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
|
(Millions, except operating data)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, NGLs and condensate
|
|
$
|
668.8
|
|
|
$
|
458.2
|
|
|
$
|
391.8
|
|
|
$
|
210.6
|
|
|
|
46
|
%
|
|
$
|
66.4
|
|
|
|
17
|
%
|
Transportation, processing and other
|
|
|
50.2
|
|
|
|
29.4
|
|
|
|
23.5
|
|
|
|
20.8
|
|
|
|
71
|
%
|
|
|
5.9
|
|
|
|
25
|
%
|
Gains (losses) from commodity derivative activity(b)
|
|
|
72.5
|
|
|
|
(83.5
|
)
|
|
|
|
|
|
|
156.0
|
|
|
|
*
|
|
|
|
(83.5
|
)
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
791.5
|
|
|
|
404.1
|
|
|
|
415.3
|
|
|
|
387.4
|
|
|
|
96
|
%
|
|
|
(11.2
|
)
|
|
|
(3
|
)%
|
Purchases of natural gas and NGLs
|
|
|
585.0
|
|
|
|
387.9
|
|
|
|
340.0
|
|
|
|
197.1
|
|
|
|
51
|
%
|
|
|
47.9
|
|
|
|
14
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin(c)
|
|
|
206.5
|
|
|
|
16.2
|
|
|
|
75.3
|
|
|
|
190.3
|
|
|
|
1,175
|
%
|
|
|
(59.1
|
)
|
|
|
(79
|
)%
|
Operating and maintenance expense
|
|
|
(32.1
|
)
|
|
|
(20.9
|
)
|
|
|
(13.5
|
)
|
|
|
11.2
|
|
|
|
54
|
%
|
|
|
7.4
|
|
|
|
55
|
%
|
Depreciation and amortization expense
|
|
|
(33.8
|
)
|
|
|
(21.9
|
)
|
|
|
(11.1
|
)
|
|
|
11.9
|
|
|
|
54
|
%
|
|
|
10.8
|
|
|
|
97
|
%
|
Earnings from equity method investments(d)
|
|
|
33.5
|
|
|
|
38.7
|
|
|
|
28.9
|
|
|
|
(5.2
|
)
|
|
|
(13
|
)%
|
|
|
9.8
|
|
|
|
34
|
%
|
Non-controlling interest in income
|
|
|
(3.9
|
)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
3.4
|
|
|
|
680
|
%
|
|
|
0.5
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
170.2
|
|
|
$
|
11.6
|
|
|
$
|
79.6
|
|
|
$
|
158.6
|
|
|
|
1,367
|
%
|
|
$
|
(68.0
|
)
|
|
|
(85
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas throughput
(MMcf/d)(d)
|
|
|
838
|
|
|
|
756
|
|
|
|
666
|
|
|
|
82
|
|
|
|
11
|
%
|
|
|
90
|
|
|
|
14
|
%
|
NGL gross production (Bbls/d)
|
|
|
20,659
|
|
|
|
22,122
|
|
|
|
19,485
|
|
|
|
(1,463
|
)
|
|
|
(7
|
)%
|
|
|
2,637
|
|
|
|
14
|
%
|
|
|
|
* |
|
Percentage change is not meaningful. |
|
(a) |
|
Includes the results from the MEG, MPP and Southern Oklahoma
acquisitions, from their respective acquisition dates of October
2008, August 2007 and May 2007. |
|
(b) |
|
Includes the effect of the acquisition of the Swap entered into
by DCP Midstream, LLC in March 2007. The Swap was for a total of
approximately 1.9 million barrels through 2012, at $66.72
per barrel. |
|
(c) |
|
Segment gross margin consists of total operating revenues,
including commodity derivative activity, less purchases of
natural gas and NGLs. Please read How We Evaluate Our
Operations above. |
|
(d) |
|
Includes our proportionate share of the throughput volumes and
earnings of East Texas and Discovery for all periods presented.
Earnings for Discovery include the amortization of the net
difference between the carrying amount of the investments and
the underlying equity of the investments. |
77
Year
Ended December 31, 2008 vs. Year Ended December 31,
2007
Total Operating Revenues Total operating
revenues increased in 2008 compared to 2007, primarily due to
the following:
|
|
|
|
|
$152.9 million increase related to commodity derivative
activity, resulting from the following:
|
|
|
|
|
|
we had a gain of $72.5 million in 2008 and a loss of
$83.5 million in 2007, resulting in an increase of
$156.0 million, which is included gains (losses) from
commodity derivative activity. This increase includes an
increase in unrealized gains of $178.8 million due to
forward prices of commodities generally being lower at the end
of the year 2008 compared to 2007. Offsetting this increase in
gain was an increase in realized cash settlement losses of
$22.8 million due to average prices of commodities
generally being higher for the year ended December 31, 2008
compared to 2007; and
|
|
|
|
we had a $3.1 million increase in unrealized loss, which is
included in sales of natural gas, NGLs and condensate;
|
|
|
|
|
|
$150.3 million increase attributable to increased commodity
prices;
|
|
|
|
$63.4 million increase attributable to higher natural gas,
NGL and condensate sales volumes, primarily as a result of the
MEG, MPP and Southern Oklahoma acquisitions, partially offset by
decreased volumes due to the impact of hurricanes; and
|
|
|
|
$20.8 million increase in transportation, processing and
other revenue as a result of the MEG and MPP acquisitions.
|
Purchases of Natural Gas and NGLs Purchases
of natural gas and NGLs increased in 2008 compared to 2007,
primarily due to increased natural gas purchase volumes
primarily as a result of the MEG, MPP and Southern Oklahoma
acquisitions, and higher costs of natural gas supply, driven by
higher commodity prices.
Segment Gross Margin Segment gross margin
increased in 2008 compared to 2007, primarily as a result of the
following:
|
|
|
|
|
$152.9 million increase related to commodity derivative
activity, as discussed in the Operating Revenues section above;
|
|
|
|
$24.1 million increase primarily attributable to an
increase in natural gas, NGL and condensate production as a
result of the MEG, MPP and Southern Oklahoma acquisitions,
partially offset by decreased volumes due to the impact of
hurricanes;
|
|
|
|
$9.0 million increase primarily attributable to changes in
contract mix; and
|
|
|
|
$4.3 million increase due to higher commodity prices.
|
Operating and Maintenance Expense Operating
and maintenance expense increased in 2008 compared to 2007,
primarily as a result of the MEG, MPP and Southern Oklahoma
acquisitions.
Depreciation and Amortization Expense
Depreciation and amortization expense increased in 2008 compared
to 2007, primarily as a result of the MEG, MPP and Southern
Oklahoma acquisitions.
Earnings from Equity Method Investments
Earnings from equity method investments decreased in 2008
compared to 2007, primarily due to decreased equity earnings of
$6.7 million from Discovery, partially offset by increased
equity earnings of $1.5 million from East Texas. Decreased
equity earnings were primarily the result of the following
variances, each representing 100% of the earnings drivers for
East Texas and Discovery;
|
|
|
|
|
Decreased equity earnings from Discovery were the result of a
decrease in Discoverys net income of $13.7 million
due primarily to $32.5 million resulting from hurricanes
Ike and Gustav, partially offset by $10.4 million higher
product margins, $4.6 million lower depreciation and
accretion expense and a 2008 reserve reversal of
$3.5 million related to a recently approved Federal Energy
Regulatory Commission rate case settlement.
|
78
|
|
|
|
|
Increased equity earnings from East Texas were the result of an
increase in East Texass net income of $6.0 million
due primarily to a $14.9 million increase as a result of
higher commodity prices, a $9.0 million increase due to
increased fee-based revenue, and decreased general and
administrative expenses of $2.9 million, partially offset
by a $12.9 million decrease due to decreased NGL
production, partially due to the effects of hurricanes and other
severe weather and an increase in operating and maintenance
expenses of $7.3 million.
|
Non-Controlling Interest in Income
Non-controlling interest in income reduced income by
$3.9 million and $0.5 million in 2008 and 2007,
respectively, and represents the non-controlling interest
holders portion of the net income of our Collbran Valley
Gas Gathering system joint venture, acquired in the MEG
acquisition and in 2008 also includes the non-controlling
interest holders portion of the net income of Jackson
Pipeline Company, acquired in the MPP acquisition.
Natural gas transported
and/or
processed increased in 2008 compared to 2007, due primarily to
increased volumes from the MEG, MPP and Southern Oklahoma
acquisitions and increased volumes from East Texas, partially
offset by decreased volumes from Pelico and Discovery. NGL
production decreased in 2008 compared to 2007, due primarily to
decreased NGL production at Discovery as a result of the
hurricanes.
Year
Ended December 31, 2007 vs. Year Ended December 31,
2006
Total Operating Revenues Total operating
revenues decreased in 2007 compared to 2006, primarily due to
the following:
|
|
|
|
|
$83.3 million decrease related to commodity derivative
activity, an increase of $0.2 million which is included in
sales of natural gas, NGLs and condensate, and a decrease of
$83.5 million which is included in losses from derivative
activity; offset by
|
|
|
|
$49.0 million increase attributable to an increase in
natural gas, NGL and condensate sales volumes, primarily as a
result of the MEG and Southern Oklahoma acquisitions, partially
offset by a decrease in natural gas sales volumes, primarily as
a result of an amendment to a contract with an affiliate in
2006, which resulted in a prospective change in the reporting of
certain Pelico revenues from a gross presentation to a net
presentation;
|
|
|
|
$17.2 million increase attributable to increased NGL and
condensate prices; and
|
|
|
|
$5.9 million increase in transportation, processing and
other services revenue primarily attributable to an increase in
natural gas throughput.
|
Purchases of Natural Gas and NGLs Purchases
of natural gas and NGLs increased in 2007 compared to 2006,
primarily due to increased natural gas purchase volumes
primarily as a result of the MEG and Southern Oklahoma
acquisitions, offset by decreased natural gas purchased volumes
primarily as a result of an amendment to a contract with an
affiliate in 2006, which resulted in a prospective change in the
reporting of certain Pelico purchases from a gross presentation
to a net presentation.
Segment Gross Margin Segment gross margin
decreased in 2007 compared to 2006, primarily as a result of the
following:
|
|
|
|
|
$83.3 million decrease related to commodity derivative
activity;
|
|
|
|
$2.5 million decrease attributable primarily to a decrease
in marketing margins from the decline in the differences in
natural gas prices at various receipt and delivery points across
our Pelico system, which were atypically high in 2006; partially
offset by
|
|
|
|
$25.2 million increase primarily attributable to an
increase in NGL and condensate production, partially as a result
of the MEG and Southern Oklahoma acquisitions, and an increase
in natural gas throughput volumes;
|
|
|
|
$1.0 million increase primarily attributable to higher
contractual fees charged to customers; and
|
|
|
|
$0.5 million increase primarily attributable to favorable
frac spreads.
|
79
NGL production and natural gas transported
and/or
processed during 2007 increased compared to 2006. These
increases were due primarily to increased volumes from
Discovery, as well as an increase in volumes from the MEG and
Southern Oklahoma acquisitions, partially offset by decreased
volumes from Pelico.
Operating and Maintenance Expense Operating
and maintenance expense increased in 2007 compared to 2006,
primarily as a result of the MEG and Southern Oklahoma
acquisitions, and higher labor and benefits and pipeline
integrity costs.
Depreciation and Amortization Expense
Depreciation and amortization expense increased in 2007 compared
to 2006, primarily as a result of the MEG and Southern Oklahoma
acquisitions.
Earnings from Equity Method Investments
Earnings from equity method investments increased in 2007
compared to 2006, primarily due to increased equity earnings of
$7.2 million from Discovery and $2.6 million from East
Texas. Increased equity earnings were primarily the result of
the following variances, each representing 100% of the earnings
drivers for East Texas and Discovery:
|
|
|
|
|
Increased equity earnings from Discovery were the result of an
increase in Discoverys net income of $18.0 million,
or 60%, due primarily to $39.0 million higher gross
processing margins resulting from higher NGL sales volumes and
NGL prices, partially offset by $9.9 million lower
fee-based transportation, gathering, processing and
fractionation revenues, $5.9 million higher operating and
maintenance expense and $2.2 million higher other expenses.
In addition, exceptionally strong commodity margins compelled
Discoverys customers to process their natural gas rather
than by-pass, which led to higher product sales revenues on
Discoverys percent-of-proceeds and keep-whole processing
contracts.
|
|
|
|
Increased equity earnings from East Texas were the result of an
increase in East Texass net income of $10.7 million,
or 22%, due primarily to a $28.5 million increase as a
result of higher commodity prices and a $1.1 million
decrease in income tax expense due to recording a deferred tax
liability of $1.8 million in 2006 related to the Texas
margin tax; partially offset by an $11.6 million decrease
due to a decline in natural gas volumes, a $3.0 million
decrease due to decreased fee-based revenue, and an increase in
operating and maintenance expenses of $2.8 million,
primarily due to increased contract services, materials and
supplies, and labor an benefits, increased depreciation expense
of $1.2 million due to the addition of a new pipeline, and
increased general and administrative expenses of
$0.6 million, primarily due to higher allocated costs from
DCP Midstream, LLC.
|
Non-Controlling Interest in Income
Non-controlling interest in income reduced income by
$0.5 million in 2007, and represents the non-controlling
interest holders portion of the net income of our Collbran
Valley Gas Gathering system joint venture, acquired in the MEG
acquisition.
80
Results
of Operations Wholesale Propane Logistics
Segment
This segment includes our propane transportation facilities,
which includes six owned rail terminals, one of which was idled
in 2007 to consolidate our operations, one leased marine
terminal, one pipeline terminal and access to several
open-access propane pipeline terminals.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variance
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007
|
|
|
2007 vs. 2006
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
|
(Millions, except operating data)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of propane
|
|
$
|
482.1
|
|
|
$
|
463.1
|
|
|
$
|
375.0
|
|
|
$
|
19.0
|
|
|
|
4
|
%
|
|
$
|
88.1
|
|
|
|
24
|
%
|
Transportation, processing and other
|
|
|
1.1
|
|
|
|
0.6
|
|
|
|
0.1
|
|
|
|
0.5
|
|
|
|
83
|
%
|
|
|
0.5
|
|
|
|
*
|
|
(Losses) gains from commodity derivative activity
|
|
|
(0.2
|
)
|
|
|
(4.1
|
)
|
|
|
0.1
|
|
|
|
(3.9
|
)
|
|
|
(95
|
)%
|
|
|
(4.2
|
)
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
483.0
|
|
|
|
459.6
|
|
|
|
375.2
|
|
|
|
23.4
|
|
|
|
5
|
%
|
|
|
84.4
|
|
|
|
23
|
%
|
Purchases of propane
|
|
|
472.0
|
|
|
|
434.1
|
|
|
|
359.2
|
|
|
|
37.9
|
|
|
|
9
|
%
|
|
|
74.9
|
|
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin(a)
|
|
|
11.0
|
|
|
|
25.5
|
|
|
|
16.0
|
|
|
|
(14.5
|
)
|
|
|
(57
|
)%
|
|
|
9.5
|
|
|
|
59
|
%
|
Operating and maintenance expense
|
|
|
(9.9
|
)
|
|
|
(10.4
|
)
|
|
|
(8.6
|
)
|
|
|
(0.5
|
)
|
|
|
(5
|
)%
|
|
|
1.8
|
|
|
|
21
|
%
|
Depreciation and amortization expense
|
|
|
(1.3
|
)
|
|
|
(1.1
|
)
|
|
|
(0.8
|
)
|
|
|
0.2
|
|
|
|
18
|
%
|
|
|
0.3
|
|
|
|
38
|
%
|
Other
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
1.5
|
|
|
|
*
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
1.3
|
|
|
$
|
14.0
|
|
|
$
|
6.6
|
|
|
$
|
(12.7
|
)
|
|
|
(91
|
)%
|
|
$
|
7.4
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane sales volume (Bbls/d)
|
|
|
21,053
|
|
|
|
22,798
|
|
|
|
21,259
|
|
|
|
(1,745
|
)
|
|
|
(8
|
)%
|
|
|
1,539
|
|
|
|
7
|
%
|
|
|
|
* |
|
Percentage change is not meaningful. |
|
(a) |
|
Segment gross margin consists of total operating revenues,
including commodity derivative activity, less purchases of
propane. Please read How We Evaluate Our Operations
above. |
Year
Ended December 31, 2008 vs. Year Ended December 31,
2007
Total Operating Revenues Total operating
revenues increased in 2008 compared to 2007, primarily due to
the following:
|
|
|
|
|
$54.1 million increase attributable to higher propane
prices;
|
|
|
|
$3.9 million increase related to commodity derivative
activity, which represents increased unrealized gains of
$5.3 million, partially offset by increased realized cash
settlement losses of $1.4 million; and
|
|
|
|
$0.5 million increase attributable to other fee revenue;
partially offset by
|
|
|
|
$35.1 million decrease attributable to decreased propane
sales volumes as a result of lower demand.
|
Purchases of Propane Purchases of propane
increased in 2008 compared to 2007, primarily due to increased
prices, partially offset by decreased purchased volumes.
Segment Gross Margin Segment gross margin
decreased in 2008 compared to 2007, primarily as a result of
increased non-cash lower of cost or market inventory adjustments
of $15.1 million due to a decline in propane prices in the
second half of 2008. We estimate that approximately half of the
2008 write downs were recovered through the sale of inventory in
2008. We also had lower per unit margins and lower propane sales
volumes, partially offset by commodity derivative activity.
Propane sales volume decreased in 2008 compared to 2007,
primarily as a result of lower demand.
81
Operating and Maintenance Expense Operating
and maintenance expense decreased in 2008 compared to 2007,
primarily due to decreased property taxes.
Other Other operating income increased due to
a payment received in the second quarter of 2008 from a supplier
related to the early termination of its supply agreement.
Year
Ended December 31, 2007 vs. Year Ended December 31,
2006
Total Operating Revenues Total operating
revenues increased in 2007 compared to 2006, primarily due to
the following:
|
|
|
|
|
$60.8 million increase attributable to higher propane
prices;
|
|
|
|
$27.3 million increase attributable to higher propane sales
volumes as a result of colder weather in the northeastern United
States and the completion of the Midland terminal, which became
operational in May 2007; and
|
|
|
|
$0.5 million increase in transportation, processing and
other services; offset by
|
|
|
|
$4.2 million decrease related to commodity derivative
activity.
|
Purchases of Propane Purchases of propane
increased in 2007 compared to 2006, primarily due to increased
prices and purchased volumes, primarily due to colder weather in
the northeastern United States and increased purchased volumes
due to the completion of the Midland terminal, which became
operational in May 2007, partially offset by decreased non-cash
lower of cost or market inventory adjustments recognized in 2007.
Segment Gross Margin Segment gross margin
increased in 2007 compared to 2006, primarily as a result of
higher per unit margins as a result of changes in contract mix
and the ability to capture lower priced supply sources,
decreased non-cash lower of cost or market inventory adjustments
recognized in 2007, and higher sales volumes primarily due to
the completion of the Midland terminal, which became operational
in May 2007, partially offset by a decrease related to commodity
derivative activity.
Propane sales volume increased in 2007 compared to 2006, due
primarily to colder weather in the northeastern United States
and the addition of the Midland terminal, which became
operational in May 2007.
Operating and Maintenance Expense Operating
and maintenance expense increased in 2007 compared to 2006,
primarily due to operating and maintenance expense at the
Midland terminal, which became operational in May 2007.
82
Results
of Operations NGL Logistics Segment
This segment includes our Seabreeze and Wilbreeze NGL
transportation pipelines and our 45% interest in Black Lake.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variance
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007
|
|
|
2007 vs. 2006
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
(Decrease)
|
|
|
Percent
|
|
|
|
(Millions, except operating data)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of NGLs
|
|
$
|
5.4
|
|
|
$
|
4.5
|
|
|
$
|
1.1
|
|
|
$
|
0.9
|
|
|
|
20
|
%
|
|
$
|
3.4
|
|
|
|
*
|
|
Transportation, processing and other
|
|
|
5.9
|
|
|
|
5.1
|
|
|
|
4.2
|
|
|
|
0.8
|
|
|
|
16
|
%
|
|
|
0.9
|
|
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
11.3
|
|
|
|
9.6
|
|
|
|
5.3
|
|
|
|
1.7
|
|
|
|
18
|
%
|
|
|
4.3
|
|
|
|
81
|
%
|
Purchases of NGLs
|
|
|
4.2
|
|
|
|
4.7
|
|
|
|
1.2
|
|
|
|
(0.5
|
)
|
|
|
(11
|
)%
|
|
|
3.5
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin(a)
|
|
|
7.1
|
|
|
|
4.9
|
|
|
|
4.1
|
|
|
|
2.2
|
|
|
|
45
|
%
|
|
|
0.8
|
|
|
|
20
|
%
|
Operating and maintenance expense
|
|
|
(1.0
|
)
|
|
|
(0.8
|
)
|
|
|
(1.6
|
)
|
|
|
0.2
|
|
|
|
25
|
%
|
|
|
(0.8
|
)
|
|
|
(50
|
)%
|
Depreciation and amortization expense
|
|
|
(1.4
|
)
|
|
|
(1.4
|
)
|
|
|
(0.9
|
)
|
|
|
|
|
|
|
|
%
|
|
|
0.5
|
|
|
|
56
|
%
|
Earnings from equity method investment(b)
|
|
|
0.8
|
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
0.2
|
|
|
|
33
|
%
|
|
|
0.3
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment net income
|
|
$
|
5.5
|
|
|
$
|
3.3
|
|
|
$
|
1.9
|
|
|
$
|
2.2
|
|
|
|
67
|
%
|
|
$
|
1.4
|
|
|
|
74
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipelines throughput (Bbls/d)(b)
|
|
|
31,407
|
|
|
|
28,961
|
|
|
|
25,040
|
|
|
|
2,446
|
|
|
|
8
|
%
|
|
|
3,921
|
|
|
|
16
|
%
|
|
|
|
* |
|
Percentage change is not meaningful. |
|
(a) |
|
Segment gross margin consists of total operating revenues less
purchases of natural gas and NGLs. Please read How We
Evaluate Our Operations above. |
|
(b) |
|
Includes our proportionate share of the throughput volumes and
earnings of Black Lake for all periods presented. Earnings for
Black Lake include the amortization of the net difference
between the carrying amount of the investment and the underlying
equity of the investment. |
Year
Ended December 31, 2008 vs. Year Ended December 31,
2007
Total Operating Revenues Total operating
revenues increased in 2008 compared to 2007, primarily due to
increased throughput volumes, increased transportation,
processing and other revenue, and increases related to
settlement of pipeline imbalances.
Purchases of NGLs Purchases of NGLs decreased
in 2008 compared to 2007, due to settlement of pipeline
imbalances, partially offset by increased throughput volumes.
Segment Gross Margin Segment gross margin
increased in 2008 compared to 2007, primarily due to increases
related to settlement of pipeline imbalances and increased
throughput volumes.
Overall, our NGL pipelines experienced an increase in throughput
volumes in 2008 as compared to 2007, primarily as a result of an
increase in processing activity associated with increased
drilling due to higher commodity prices.
Earnings from Equity Method Investments
Earnings from equity method investments increased in 2008
compared to 2007, due to increased throughput volumes resulting
in higher Black Lake equity earnings.
Year
Ended December 31, 2007 vs. Year Ended December 31,
2006
Total Operating Revenues Total operating
revenues increased in 2007 compared to 2006, primarily due to
changes in product mix and increased volumes, as well as
increased transportation, processing and other revenue.
Increased volumes and transportation, processing and other
revenue are primarily as a result of the addition of our
Wilbreeze pipeline in December 2006.
83
Purchases of NGLs Purchases of NGLs increased
in 2007 compared to 2006, primarily due to changes in product
mix and increased volumes.
Segment Gross Margin Segment gross margin
increased in 2007 compared to 2006, primarily due to changes in
product mix and increased volumes, as well as increased
transportation, processing and other revenue.
Overall, our NGL pipelines experienced an increase in throughput
volumes during 2007 as compared to 2006, primarily as a result
of the addition of our Wilbreeze pipeline.
Operating and Maintenance Expense Operating
and maintenance expense decreased in 2007 compared to 2006,
primarily due to lower pipeline integrity costs on our Seabreeze
pipeline.
Depreciation and Amortization Expense
Depreciation and amortization expense increased in 2007 compared
to 2006, primarily as a result of the addition of our Wilbreeze
pipeline.
Earnings from Equity Method Investments
Earnings from equity method investments increased in 2007
compared to 2006, due to higher Black Lake revenues, partially
offset by increased project costs.
Liquidity
and Capital Resources
We expect our sources of liquidity to include:
|
|
|
|
|
cash generated from operations;
|
|
|
|
cash distributions from our equity method investments;
|
|
|
|
borrowings under our revolving credit facility;
|
|
|
|
cash realized from the liquidation of securities that are
pledged under our term loan facility;
|
|
|
|
issuance of additional partnership units;
|
|
|
|
debt offerings;
|
|
|
|
guarantees issued by DCP Midstream, LLC, which reduce the amount
of collateral we may be required to post with certain
counterparties to our commodity derivative instruments; and
|
|
|
|
letters of credit.
|
We anticipate our more significant uses of resources to include:
|
|
|
|
|
capital expenditures;
|
|
|
|
contributions to our equity method investments to finance our
share of their capital expenditures;
|
|
|
|
business and asset acquisitions;
|
|
|
|
collateral with counterparties to our swap contracts to secure
potential exposure under these contracts, which may, at times,
be significant depending on commodity price movements, and which
is required to the extent we exceed certain guarantees issued by
DCP Midstream, LLC and letters of credit we have posted; and
|
|
|
|
quarterly distributions to our unitholders.
|
We believe that cash generated from these sources will be
sufficient to meet our short-term working capital requirements,
long-term capital expenditure and acquisition requirements, and
quarterly cash distributions for the next twelve months. In the
event these sources are not sufficient, we would reduce our
discretionary spending, which may include capital spending.
Beginning in the third quarter of 2008, the capital markets
experienced volatility, uncertainty and interventions by various
governments around the globe. The effects of these market
conditions include significant changes in the valuation of
equity securities and overnight and longer-term borrowing rates.
The availability of credit through traditional sources of
funding such as the commercial paper, bank lending and
84
the private and public placement debt markets also decreased
dramatically. In these market conditions, it is uncertain if we
would be successful in obtaining timely additional funding from
the traditional equity or debt markets if it were needed.
Furthermore, the cost of such new funding could substantially
exceed the cost of funds previously obtained. Based on current
and anticipated levels of operations, we believe we have
adequate committed financial resources to conduct our business,
although deterioration in our operating environment beyond that
currently anticipated could limit our borrowing capacity as well
as impact our compliance with the Credit Agreements
financial covenant requirements.
Changes in natural gas, NGL and condensate prices and the terms
of our processing arrangements have a direct impact on our
generation and use of cash from operations due to their impact
on net income, along with the resulting changes in working
capital. We have mitigated a significant portion of our
anticipated commodity price risk associated with the equity
volumes from our gathering and processing operations through
2013 with fixed price natural gas and crude oil swaps. For
additional information regarding our derivative activities,
please read Quantitative and Qualitative
Disclosures about Market Risk Commodity Price
Risk Commodity Cash Flow Protection Activities.
Our banking group is comprised of various financial
institutions, of which certain institutions have recently
merged. We do not expect the aggregate contractual financial
commitment of these institutions to us to change during the
remaining life of our existing credit agreement as a result of
these mergers.
The capacity under our Credit Agreement is approximately
$824.6 million, net of Lehman Brothers unfunded
commitment. Our borrowing capacity may be limited by the Credit
Agreements financial covenant requirements. Except in the
case of a default, which would make the borrowings under the
Credit Agreement fully callable, amounts borrowed under our
Credit Agreement will not mature prior to the June 21, 2012
maturity date. As of February 23, 2009, we had
approximately $228.0 million of net available borrowings
under our Credit Agreement.
Certain of our counterparties are experiencing financial
difficulties, which did not have a significant impact on our
business in 2008.
The counterparties to each of our commodity swap contracts are
investment-grade rated financial institutions. Under these
contracts, we may be required to provide collateral to the
counterparties in the event that our potential payment exposure
exceeds a predetermined collateral threshold. Collateral
thresholds are set by us and each counterparty, as applicable,
in the master contract that governs our financial transactions
based on our and the counterpartys assessment of
creditworthiness. The assessment of our position with respect to
the collateral thresholds are determined on a counterparty by
counterparty basis, and are impacted by the representative
forward price curves and notional quantities under our swap
contracts. Due to the interrelation between the representative
crude oil and natural gas forward price curves, it is not
practical to determine a single pricing point at which our swap
contracts will meet the collateral thresholds as we may transact
multiple commodities with the same counterparty. As of
February 23, 2009, DCP Midstream, LLC had issued and
outstanding parental guarantees totaling $83.0 million to
certain counterparties to our commodity derivative instruments
to mitigate a portion of our collateral requirements with these
counterparties. Prior to our initial public offering, DCP
Midstream, LLC provided parental guarantees to certain
counterparties to our commodity derivative instruments, totaling
$43.0 million as of February 23, 2009. In July 2008,
DCP Midstream, LLC provided additional parental guarantees to
certain counterparties to our commodity derivative instruments,
totaling $40.0 million as of February 23, 2009. We pay
DCP Midstream, LLC a fee of 0.5% per annum on $40.0 million
of these guarantees. The fee on the remaining guarantees is
covered under the omnibus agreement with DCP Midstream, LLC. As
of February 23, 2009, we had a letter of credit of
$10.0 million. These parental guarantees and letter of
credit reduce the amount of cash we may be required to post as
collateral. This letter of credit was issued directly by a
financial institution and does not reduce the available capacity
under our credit facility. As of February 23, 2009, we had
no cash collateral posted with counterparties. Depending on
daily commodity prices, the amount of collateral posted can go
up or down on a daily basis. Predetermined collateral thresholds
for commodity derivative instruments guaranteed by DCP
Midstream, LLC are generally dependent on DCP Midstream,
LLCs credit rating and the thresholds would be reduced to
$0 in the event DCP Midstream, LLCs credit rating were to
fall below investment grade.
85
Discovery is owned 40% by us and 60% by Williams Partners, LP.
Discovery is managed by a two-member management committee,
consisting of one representative from each owner. The members of
the management committee have voting power corresponding to
their respective ownership interests in Discovery. All actions
and decisions relating to Discovery require the unanimous
approval of the owners except for a few limited situations.
Discovery must make quarterly distributions of available cash
(generally, cash from operations less required and discretionary
reserves) to its owners. The management committee, by majority
approval, will determine the amount of the distributions. In
addition, the owners are required to offer to Discovery all
opportunities to construct pipeline laterals within an
area of interest. Calls for capital contributions
are determined by a vote of the management committee and require
unanimous approval of both owners in most instances.
East Texas is owned 25% by us and 75% by DCP Midstream, LLC.
East Texas is managed by a four-member management committee,
consisting of two representatives from each owner. The members
of the management committee have voting power corresponding to
their respective ownership interests in East Texas. Most
significant actions relating to East Texas require the unanimous
approval of both owners. East Texas must make quarterly
distributions of available cash (generally, cash from operations
less required and discretionary reserves) to its owners. The
management committee, by majority approval, will determine the
amount of the distributions. Calls for capital contributions are
determined by a vote of the management committee and require
unanimous approval of both owners except in certain situations,
such as the breach or default of a material agreement or payment
obligation, that are reasonably likely to have a material
adverse effect on the business, operations or financial
condition of East Texas.
Working Capital Working capital is the
amount by which current assets exceed current liabilities.
Current assets are reduced by our quarterly distributions, which
are required under the terms of our partnership agreement based
on Available Cash, as defined in the partnership agreement. In
general, our working capital is impacted by changes in the
prices of commodities that we buy and sell, along with other
business factors that affect our net income and cash flows. Our
working capital is also impacted by the timing of operating cash
receipts and disbursements, borrowings of and payments on debt,
capital expenditures, and increases or decreases in restricted
investments and other long-term assets.
As of December 31, 2008, we had $48.0 million in cash
and cash equivalents. Of this balance, as of December 31,
2008, $21.2 million was held by Collbran Valley Gas
Gathering, or Collbran, our 70% owned joint venture which we
consolidate in our financial results. Other than the cash held
by Collbran, this cash balance was available for general
corporate purposes.
We had working capital of $40.4 million as of
December 31, 2008 and a working capital deficit of
$1.1 million as of December 31, 2007. The changes in
working capital are primarily attributable to the factors
described above. We expect that our future working capital
requirements will continue to be impacted by the factors
identified above.
Cash Flow Operating, investing and
financing activities was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Net cash provided by operating activities
|
|
$
|
101.5
|
|
|
$
|
65.4
|
|
|
$
|
94.8
|
|
Net cash used in investing activities
|
|
$
|
(166.9
|
)
|
|
$
|
(521.7
|
)
|
|
$
|
(93.8
|
)
|
Net cash provided by financing activities
|
|
$
|
88.9
|
|
|
$
|
434.6
|
|
|
$
|
3.0
|
|
Our predecessors sources of liquidity, prior to their
acquisition by us, included cash generated from operations and
funding from DCP Midstream, LLC. Our predecessors cash
receipts were deposited in DCP Midstream, LLCs bank
accounts and all cash disbursements were made from these
accounts. Cash transactions for our predecessor were handled by
DCP Midstream, LLC and were reflected in partners equity
as intercompany advances from DCP Midstream, LLC. We maintain
our own bank accounts, which are managed by DCP Midstream, LLC.
86
Net Cash Provided by Operating Activities The
changes in net cash provided by operating activities are
attributable to our net income adjusted for non-cash charges as
presented in the consolidated statements of cash flows and
changes in working capital as discussed above.
We and our predecessors received cash distributions from equity
method investments of $59.9 million, $38.9 million and
$25.9 million during the years ended December 31,
2008, 2007 and 2006, respectively. Distributions exceeded
earnings by $25.6 million for the year ended
December 31, 2008. Earnings exceeded distributions by
$0.4 million and $3.3 million for the years ended
December 31, 2007 and 2006, respectively.
Net Cash Used in Investing Activities Net
cash used in investing activities during 2008 was primarily used
for: (1) acquisition of MPP of $146.4 million;
acquisition of the MEG subsidiaries of $10.9 million;
(2) capital expenditures of $41.0 million, which
generally consisted of expenditures for construction and
expansion of our infrastructure in addition to well connections
and other upgrades to our existing facilities, including the
pipeline integrity costs and system upgrades at Douglas and
(3) investments in equity method investments of
$13.8 million; and (4) acquisition of the MEG
subsidiaries of $10.9 million; which were partially offset
by (5) net proceeds from available-for-sale securities of
$42.3 million; and (6) $2.9 million proceeds from
the sale of assets.
Net cash used in investing activities during 2007 was primarily
used for: (1) asset acquisitions of $191.3 million;
(2) acquisition of equity method investments of
$153.3 million; (3) acquisition of the MEG
subsidiaries of $142.0 million; (4) capital
expenditures of $21.3 million, which generally consisted of
expenditures for construction and expansion of our
infrastructure in addition to well connections and other
upgrades to our existing facilities and (5) investments in
equity method investments of $16.3 million; which were
partially offset by; (6) net proceeds from
available-for-sale securities of $2.4 million.
During 2007, we acquired Discovery, East Texas and the Swap from
DCP Midstream, LLC for an initial cash outlay of approximately
$243.7 million. The historical value of the assets acquired
of approximately $153.3 million is reflected in net
cash used in investing activities. The remaining
$90.4 million is reflected in net cash provided by
financing activities.
During 2006, we acquired our wholesale propane logistics
business from DCP Midstream, LLC, for an initial cash outlay of
approximately $67.4 million. The historical value of the
assets acquired of approximately $56.7 million is reflected
in net cash used in investing activities. The
remaining $10.7 million is reflected in net cash
provided by financing activities as the excess of the
purchase price over the acquired assets.
We invested cash in equity method investments of
$13.8 million, $16.3 million and $11.1 million
during the years ended December 31, 2008, 2007 and 2006,
respectively, of which $12.2 million, $6.9 million and
$11.1 million, respectively, was to fund our share of
capital expansion projects, $1.6 million in 2008 was to
fund hurricane expenses and $9.4 million in 2007 was to
fund working capital needs.
Net cash used in investing activities in 2006 was also used for
capital expenditures, which generally consisted of expenditures
for construction and expansion of our infrastructure in addition
to well connections and other upgrades to our existing
facilities.
Net Cash Provided By Financing Activities Net
cash provided by financing activities during 2008 was comprised
of; (1) proceeds from debt of $660.4 million;
(2) the issuance of common units for $132.1 million,
net of offering costs; (3) contributions from DCP
Midstream, LLC of $4.1 million; and (4) net
contributions from non-controlling interests of
$2.4 million; partially offset by (5) repayment of
debt of $633.9 million; and (6) distributions to our
unitholders and general partner of $76.2 million.
During 2008, total outstanding indebtedness under our
$824.6 million credit agreement, which includes borrowings
under our revolving credit facility, our term loan facility and
letters of credit issued under the credit agreement, was not
less than $630.2 million and did not exceed
$735.3 million. The weighted average indebtedness
outstanding was $643.1 million, $690.0 million,
$655.4 million and $666.6 million for the first,
second, third and fourth quarters of 2008, respectively.
We had liquidity, which includes available commitments under the
Credit Agreement and excludes cash on hand, of
$364.7 million, $385.4 million, $390.4 million
and $228.0 million at the end of the first, second,
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third and fourth quarters of 2008, respectively, which has been
reduced by Lehman non-participation for all periods for
comparative purposes.
During 2008, we had the following borrowings:
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$320.4 million borrowings for cash collateral postings with
our commodity derivative contracts and for general working
capital purposes. $293.9 million of these borrowings were
repaid as of December 31, 2008;
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$150.0 million borrowing on our term loan facility, the
proceeds of which were used to reduce borrowings on our
revolving credit facility; and
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$190.0 million borrowing from our revolving credit
facility, $146.4 million of which was used for the Michigan
acquisition and the remainder was used for other capital
expenditures.
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Net cash provided by financing activities during 2007 was
comprised of borrowings of $579.0 million, the issuance of
common units for $228.5 million, net of offering costs, and
contributions from non-controlling interests of
$3.4 million, offset by repayment of debt of
$217.0 million, the excess of purchase price over the
acquired assets attributable to a payment related to our
acquisition of Discovery, East Texas and the Swap of
$90.4 million and of our wholesale propane logistics
business of $9.9 million, distributions to our unitholders
of $44.0 million, and net change in advances from DCP
Midstream, LLC of $14.6 million.
During 2007, we had the following borrowings:
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$11.0 million under our revolving credit facility to fund
the purchase of the Laser assets from Midstream;
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$89.0 million under our revolving credit facility to
partially fund the Southern Oklahoma acquisition;
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$88.0 million under a bridge loan to partially fund the
Southern Oklahoma acquisition, which was extinguished with
borrowings under our revolving credit facility;
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$246.0 million from our revolving credit facility to
finance the acquisition of our interests in East Texas and
Discovery;
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$100.0 million from our term loan facility and
$35.0 million from our revolving credit facility to finance
the MEG acquisition and for general corporate purposes; and
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$10.0 million from our revolving credit facility for
general corporate purposes, which was subsequently repaid.
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Net cash provided by financing activities in 2006 was primarily
comprised of borrowings on our credit facility, which we used to
fund the acquisition of our wholesale propane logistics
business, partially offset by distributions to our unitholders,
repayments of debt, changes in parent advances and the excess
purchase price of our wholesale propane logistics business over
its historical basis.
We expect to continue to use cash in financing activities for
the payment of distributions to our unitholders and general
partner. See Note 12 of the Notes to Consolidated Financial
Statements in Item 8. Financial Statements and
Supplementary Data.
Capital Requirements The midstream
energy business can be capital intensive, requiring significant
investment to maintain and upgrade existing operations. Our
capital requirements have consisted primarily of, and we
anticipate will continue to consist of the following:
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maintenance capital expenditures, which are cash expenditures
where we add on to or improve capital assets owned or acquire or
construct new capital assets if such expenditures are made to
maintain, including over the long term, our operating capacity
or revenues; and
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expansion capital expenditures, which are cash expenditures for
acquisitions or capital improvements (where we add on to or
improve the capital assets owned, or acquire or construct new
gathering lines, treating facilities, processing plants,
fractionation facilities, pipelines, terminals, docks, truck
racks,
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tankage and other storage, distribution or transportation
facilities and related or similar midstream assets) in each case
if such addition, improvement, acquisition or construction is
made to increase our operating capacity or revenues.
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We incur capital expenditures for our consolidated entities and
our equity method investments. We anticipate maintenance capital
expenditures of $10.0 to $15.0 million, and expansion
capital expenditures of $65.0 million, for the year ending
December 31, 2009. Maintenance capital includes an
estimated $5.0 million to complete the pipeline integrity
and system upgrades to our Douglas system. DCP Midstream, LLC
has agreed to reimburse us for our share of Discoverys
capital expenditures for the Tahiti pipeline lateral. The board
of directors may approve additional growth capital during the
year, at their discretion.
Our capital expenditures, excluding acquisitions, totaled
$41.0 million and $21.3 million, including maintenance
capital expenditures of $11.3 million and
$2.4 million, and expansion capital expenditures of
$29.7 million and $18.9 million, during 2008 and 2007,
respectively. Maintenance capital in 2008 included
$6.8 million associated with the pipeline integrity and
system upgrades to our Douglas system. In conjunction with the
acquisition of our investments in East Texas and Discovery, we
entered into an agreement with DCP Midstream, LLC whereby DCP
Midstream, LLC will reimburse East Texas for 25%, and will
reimburse us for 40%, of certain capital expenditures as defined
in the agreement, from July 1, 2007 through completion of
the capital projects, for a period not to exceed three years. In
the second quarter of 2006, we entered into a letter agreement
with DCP Midstream, LLC whereby DCP Midstream, LLC made capital
contributions to reimburse us for certain capital projects. We
also have an agreement with certain producers whereby these
producers will reimburse us for certain capital projects
completed by us. As a result, during the year ended
December 31, 2008, we had an increase in receivables of
$0.3 million and during the year ended December 31,
2007, we had a decrease in receivables of $0.2 million
related to collections of maintenance capital expenditures from
DCP Midstream, LLC and producers. As a result, our total
maintenance capital expenditures net of reimbursements were
approximately $11.0 million and $2.6 million for the
years ended December 31, 2008 and 2007, respectively.
During the third quarter of 2008, we announced that Collbran
Valley Gas Gathering, LLC, or Collbran, plans to invest
approximately $150.0 million over a multi-year period to
construct approximately 20 miles of
24-inch
diameter gathering pipeline, and compression and liquids
handling facilities, to support its Colorado system, located in
the Collbran Valley area of the Piceance Basin in western
Colorado. We are the operator and 70% owner of Collbran. We
ultimately expect to invest approximately $105.0 million in
this project, which is in proportion to our ownership interest.
The gathering system is designed to ultimately have throughput
capacity of over 600 million cubic feet per day, or
MMcf/d, and
is supported by long-term acreage dedications. Our share of the
Collbran investment was approximately $5.6 million in 2008
and we will invest approximately $57.0 million in 2009 to
achieve throughput capacity of approximately
200 MMcf/d
in the third quarter of 2009. Our share of the remaining
investment in primarily compression equipment of approximately
$42.4 million may be spent in 2010 and beyond as production
volumes increase, providing total throughput capacity in excess
of
600 MMcf/d.
During the third quarter of 2008, we announced plans, along with
DCP Midstream, LLC, to invest approximately $56.0 million
in East Texas to construct a gathering pipeline to support the
East Texas system. Our interest in this pipeline is currently
25%. Our net investment is approximately $14.0 million. Of
that total, we spent approximately $1.3 million in 2008 and
expect to spend the remaining $12.7 million in 2009. The
pipeline is scheduled to be operational during the second
quarter of 2009.
During the third quarter of 2008, we announced plans to pursue
development of a natural gas pipeline in the Haynesville shale
in northern Louisiana. Development of a potential pipeline
project is highly dependent upon drilling and development plans
in the area, securing appropriate levels of shipper contractual
commitments and securing financing. We spent approximately
$2.3 million in 2008 on this project.
We intend to make cash distributions to our unitholders and our
general partner. Due to our cash distribution policy, we expect
that we will distribute to our unitholders most of the cash
generated by our operations. As a result, we expect that we will
rely upon external financing sources, which could include other
debt and common unit issuances, to fund our acquisition and
expansion capital expenditures.
89
We expect to fund future capital expenditures with restricted
investments, funds generated from our operations, borrowings
under our credit facility and the issuance of additional
partnership units. If these sources are not sufficient, we may
reduce our capital spending.
Given our long-term strategy of profitable growth, our long-term
objective is to obtain an investment grade credit rating, to
increase our available sources to fund capital expenditures.
Cash Distributions to Unitholders Our
partnership agreement requires that, within 45 days after
the end of each quarter, we distribute all Available Cash, as
defined in the partnership agreement. We made cash distributions
to our unitholders and general partner of $76.2 million and
$44.0 million during 2008 and 2007, respectively. We intend
to continue making quarterly distribution payments to our
unitholders to the extent we have sufficient cash from
operations after the establishment of reserves.
Description of the Credit Agreement On
June 21, 2007, we entered into an Amended and Restated
Credit Agreement, or the Credit Agreement, which amended our
existing Credit Agreement. This new
5-year
Credit Agreement consists of a $764.6 million revolving
credit facility and a $60.0 million term loan facility, and
matures on June 21, 2012. The amendment also improved
pricing and certain other terms and conditions of the Credit
Agreement. As of December 31, 2008, the outstanding balance
on the revolving credit facility was $596.5 million and the
outstanding balance on the term loan facility was
$60.0 million.
Our obligations under the revolving credit facility are
unsecured, and the term loan facility is secured at all times by
high-grade securities, which are classified as restricted
investments in the accompanying consolidated balance sheets, in
an amount equal to or greater than the outstanding principal
amount of the term loan. Any portion of the term loan balance
may be repaid at any time, and we would then have access to a
corresponding amount of the collateral securities. Upon any
prepayment of term loan borrowings, the amount of our revolving
credit facility will automatically increase to the extent that
the repayment of our term loan facility is made in connection
with an acquisition of assets in the midstream energy business.
The unused portion of the revolving credit facility may be used
for letters of credit. At December 31, 2008 and 2007, there
were outstanding letters of credit issued under the Credit
Agreement of $0.3 million and $0.2 million,
respectively.
We may prepay all loans at any time without penalty, subject to
the reimbursement of lender breakage costs in the case of
prepayment of London Interbank Offered Rate, or LIBOR,
borrowings. Indebtedness under the revolving credit facility
bears interest at either: (1) the higher of Wachovia
Banks prime rate or the Federal Funds rate plus 0.50%; or
(2) LIBOR plus an applicable margin, which ranges from
0.23% to 0.575% dependent upon our leverage level or credit
rating. As of December 31, 2008, the weighted-average
interest rate on our revolving credit facility was 2.08% per
annum. The revolving credit facility incurs an annual facility
fee of 0.07% to 0.175% depending on our applicable leverage
level or debt rating. This fee is paid on drawn and undrawn
portions of the revolving credit facility. The term loan
facility bears interest at a rate equal to either:
(1) LIBOR plus 0.10%; or (2) the higher of Wachovia
Banks prime rate or the Federal Funds rate plus 0.50%. As
of December 31, 2008, the interest rate on our term loan
facility was 1.54%.
The Credit Agreement prohibits us from making distributions of
Available Cash to unitholders if any default or event of default
(as defined in the Credit Agreement) exists. The Credit
Agreement requires us to maintain a leverage ratio (the ratio of
our consolidated indebtedness to our consolidated EBITDA, in
each case as is defined by the Credit Agreement) of not more
than 5.0 to 1.0, and on a temporary basis for not more than
three consecutive quarters (including the quarter in which such
acquisition is consummated) following the consummation of asset
acquisitions in the midstream energy business of not more than
5.5 to 1.0. The Credit Agreement also requires us to maintain an
interest coverage ratio (the ratio of our consolidated EBITDA to
our consolidated interest expense, in each case as is defined by
the Credit Agreement) of equal or greater than 2.5 to 1.0
determined as of the last day of each quarter for the
four-quarter period ending on the date of determination.
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Bridge
Loan
In May 2007, we entered into a two-month bridge loan, or the
Bridge Loan, which provided for borrowings up to
$100.0 million, and had terms and conditions substantially
similar to those of our Credit Agreement. In conjunction with
our entering into the Bridge Loan, our Credit Agreement was
amended to provide for additional unsecured indebtedness, of an
amount not to exceed $100.0 million, which was due and
payable no later than August 9, 2007.
We used borrowings on the Bridge Loan of $88.0 million to
partially fund the Southern Oklahoma acquisition. The remaining
$12.0 million available for borrowing on the Bridge Loan
was not utilized. We used a portion of the net proceeds of the
private placement to extinguish the $88.0 million
outstanding on the Bridge Loan in June 2007.
Total
Contractual Cash Obligations and Off-Balance Sheet
Obligations
A summary of our total contractual cash obligations as of
December 31, 2008, is as follows:
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Payments Due by Period
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2014 and
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Total
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2009
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2010-2011
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2012-2013
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Thereafter
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(Millions)
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Long-term debt(a)
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$
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733.4
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$
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26.6
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$
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42.4
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$
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664.4
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$
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Operating lease obligations
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44.7
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12.4
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16.9
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12.8
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2.6
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Purchase obligations(b)
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632.8
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140.8
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201.9
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188.2
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101.9
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Other long-term liabilities(c)
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8.5
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0.4
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0.1
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8.0
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Total
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$
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1,419.4
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$
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179.8
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$
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261.6
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$
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865.5
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$
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112.5
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(a) |
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Includes interest payments on long-term debt that has been
hedged, because the interest rate is determinable. Interest
payments on long-term debt, which has not been hedged, are not
included as they are based on floating interest rates and we
cannot determine with accuracy the periodic repayment dates or
the amounts of the interest payments. |
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Purchase obligations include $3.3 million of purchase
orders for capital expenditures and $629.5 million of
various non-cancelable commitments to purchase physical
quantities of commodities in future periods. For contracts where
the price paid is based on an index, the amount is based on the
forward market prices at December 31, 2008. Purchase
obligations exclude accounts payable, accrued interest payable
and other current liabilities recognized in the consolidated
balance sheets. Purchase obligations also exclude current and
long-term unrealized losses on derivative instruments included
in the consolidated balance sheet, which represent the current
fair value of various derivative contracts and do not represent
future cash purchase obligations. These contracts may be settled
financially at the difference between the future market price
and the contractual price and may result in cash payments or
cash receipts in the future, but generally do not require
delivery of physical quantities of the underlying commodity. In
addition, many of our gas purchase contracts include short and
long term commitments to purchase produced gas at market prices.
These contracts, which have no minimum quantities, are excluded
from the table. |
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Other long-term liabilities include $7.9 million of asset
retirement obligations and $0.6 million of environmental
reserves, recognized on the consolidated balance sheet. |
Our off-balance arrangements consist solely of our operating
lease obligations.
Recent
Accounting Pronouncements
Statement of Financial Accounting Standards, or SFAS,
No. 162 The Hierarchy of Generally Accepted
Accounting Principles, or
SFAS 162 In May 2008, the Financial
Accounting Standards Board, or FASB, issued SFAS 162, which
is intended to improve financial reporting by identifying a
consistent framework, or hierarchy, for selecting accounting
principles to be used in preparing financial statements that are
presented in conformity with GAAP for nongovernmental entities.
SFAS 162 is effective 60 days following
91
the SECs approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The
Meaning of Present Fairly in Conformity with Generally Accepted
Accounting Principles. We have assessed the impact of the
adoption of SFAS 162, and believe that there will be no
impact on our consolidated results of operations, cash flows or
financial position.
FASB Staff Position, or FSP,
No. SFAS 142-3
Determination of the Useful Life of Intangible
Assets, or
FSP 142-3
In April 2008, the FASB issued
FSP 142-3,
which amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible.
FSP 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008, and interim periods
within those fiscal years. We are in the process of assessing
the impact of
FSP 142-3
but do not expect a material impact on our consolidated results
of operations, cash flows and financial position as a result of
adoption.
SFAS No. 161 Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133, or
SFAS 161 In March 2008, the FASB issued
SFAS 161, which requires disclosures of how and why an
entity uses derivative instruments, how derivative instruments
and related hedged items are accounted for and how derivative
instruments and related hedged items affect an entitys
financial position, financial performance, and cash flows.
SFAS 161 is effective for us on January 1, 2009. We
are in the process of assessing the impact of SFAS 161 on
our disclosures, and will make the required disclosures in our
March 31, 2009 consolidated financial statements.
SFAS No. 160 Noncontrolling Interests in
Consolidated Financial Statements, an amendment of Accounting
Research Bulletin No. 51, or SFAS 160
In December 2007, the FASB issued SFAS 160,
which establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than
the parent, the amount of consolidated net income attributable
to the parent and to the noncontrolling interest, changes in a
parents ownership interest and the valuation of retained
noncontrolling equity investments when a subsidiary is
deconsolidated. SFAS 160 also establishes reporting
requirements that provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and
the interests of the noncontrolling owners. SFAS 160 was
effective for us on January 1, 2009, and did not have a
significant impact on our consolidated results of operations,
cash flows or financial position. As a result of adoption
effective January 1, 2009, we will reclassify our non-
controlling interests in the consolidated balance sheets to
partners equity.
SFAS No. 141(R) Business Combinations
(revised 2007), or SFAS 141(R) In
December 2007, the FASB issued SFAS 141(R), which requires
the acquiring entity in a business combination to recognize all
(and only) the assets acquired and liabilities assumed in the
transaction; establishes the acquisition-date fair value as the
measurement objective for all assets acquired and liabilities
assumed; and requires the acquirer to disclose to investors and
other users all of the information they need to evaluate and
understand the nature and financial effect of the business
combination. SFAS 141(R) is effective for us on
January 1, 2009. As this standard will be applied
prospectively upon adoption, we will account for all
transactions with closing dates subsequent to the adoption date
in accordance with the provisions of the standard.
SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities including
an amendment of FAS 115, or
SFAS 159 In February 2007, the FASB issued
SFAS 159, which allows entities to choose, at specified
election dates, to measure eligible financial assets and
liabilities at fair value that are not otherwise required to be
measured at fair value. If a company elects the fair value
option for an eligible item, changes in that items fair
value in subsequent reporting periods must be recognized in
current earnings. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparison between
entities that elect different measurement attributes for similar
assets and liabilities. The provisions of SFAS 159 became
effective for us on January 1, 2008. We have not elected
the fair value option relative to any of our financial assets
and liabilities which are not otherwise required to be measured
at fair value by other accounting standards. Therefore, there is
no effect of adoption reflected in our consolidated results of
operations, cash flows or financial position.
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SFAS No. 157, Fair Value
Measurements, or SFAS 157 In
September 2006, the FASB issued SFAS 157, which was
effective for us on January 1, 2008. SFAS 157:
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defines fair value as the price that would be received to sell
an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date;
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establishes a framework for measuring fair value;
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establishes a three-level hierarchy for fair value measurements
based upon the transparency of inputs to the valuation of an
asset or liability as of the measurement date;
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nullifies the guidance in Emerging Issues Task Force, or EITF,
02-3,
Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Involved in Energy Trading and Risk
Management Activities, which required the deferral of profit
at inception of a transaction involving a derivative financial
instrument in the absence of observable data supporting the
valuation technique; and
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significantly expands the disclosure requirements around
instruments measured at fair value.
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Upon the adoption of this standard we incorporated the
marketplace participant view as prescribed by SFAS 157.
Such changes included, but were not limited to, changes in
valuation policies to reflect an exit price methodology, the
effect of considering our own non-performance risk on the
valuation of liabilities, and the effect of any change in our
credit rating or standing. As a result of adopting
SFAS 157, we recorded a transition adjustment of
approximately $5.8 million as an increase to earnings and
approximately $1.3 million as an increase to AOCI during
the three months ended March 31, 2008. All changes in our
valuation methodology have been incorporated into our fair value
calculations subsequent to adoption.
Pursuant to FASB Staff Position
157-2, the
FASB issued a partial deferral, ending on December 31,
2008, of the implementation of SFAS 157 as it relates to
all non-financial assets and liabilities where fair value is the
required measurement attribute by other accounting standards.
While we have adopted SFAS 157 for all financial assets and
liabilities effective January 1, 2008, we are in the
process of assessing the impact SFAS 157 will have on our
non-financial assets and liabilities, but do not expect a
material impact on our consolidated results of operations, cash
flows or financial positions upon adoption.
FSP
No. 157-3
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active, or
FSP 157-3
In October 2008, the FASB issued
FSP 157-3,
which provides guidance in situations where a) observable
inputs do not exist, b) observable inputs exist but only in
an inactive market and c) how market quotes should be
considered when assessing the relevance of observable and
unobservable inputs to determine fair value.
FSP 157-3
was effective upon issuance, including prior periods for which
financial statements have not been issued. We believe that the
financial assets that are reflected in our financial statements
are transacted within active markets, and therefore no
adjustment to our fair value methodology was required and there
is no effect on our consolidated results of operations, cash
flows or financial positions as a result of the adoption of this
FSP.
FSP of Financial Interpretation, or FIN,
39-1,
Amendment of FASB Interpretation No. 39, or
FSP
FIN 39-1
In April 2008, the FASB issued FSP
FIN 39-1,
which permits, but does not require, a reporting entity to
offset fair value amounts recognized for the right to reclaim
cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against the fair value amounts recognized
for derivative instruments executed with the same counterparty
under a master netting arrangement. FSP
FIN 39-1
became effective for us beginning on January 1, 2008;
however, we have elected to continue our policy of reflecting
our derivative asset and liability positions, as well as any
cash collateral, on a gross basis in our consolidated balance
sheets.
EITF 08-06
Equity Method Investment Accounting
Considerations, or
EITF 08-06
In November 2008, the EITF issued ETIF
08-06.
Although the issuance of FAS 141(R) and FAS 160 were
not intended to reconsider the accounting for equity method
investments, the application of the equity method is affected by
the issuance of these standards. This issue addresses
a) how the initial carrying value of an equity method
investment should be determined; b) how an impairment
assessment of an underlying indefinite-lived intangible asset of
an equity method investment should be performed; c) how an
equity method investees
93
issuance of shares should be accounted for and d) how to
account for a change in an investment from the equity method to
the cost method. This issue is effective for us on
January 1, 2009, and although we do not expect any changes
to the manner in which we apply equity method accounting, this
guidance will be considered on a prospective basis to
transactions with equity method investees.
EITF 07-04
Application of the Two-Class Method under FASB
Statement No. 128 to Master Limited Partnerships
or
EITF 07-04
In March 2008, the EITF issued ETIF
07-04. This
issue seeks to improve the comparability of earnings per unit,
or EPU, calculations for master limited partnerships with
incentive distribution rights in accordance with FASB Statement
No. 128 and its related interpretations. This issue is
effective for us on January 1, 2009 and will be
incorporated into our EPU calculations beginning with the
quarter ending March 31, 2009. We are in the process of
assessing the impact of
EITF 07-04
on our EPU calculations, and will make any required changes to
our calculation methodology for the quarter ending
March 31, 2009.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
Market risk is the risk of loss arising from adverse change in
market prices and rates. We are exposed to market risks,
including changes in commodity prices and interest rates. We may
use financial instruments such as forward contracts, swaps and
futures to mitigate the effects of identified risks. In general,
we attempt to mitigate risks related to the variability of
future earnings and cash flows resulting from changes in
applicable commodity prices or interest rates so that we can
maintain cash flows sufficient to meet debt service, required
capital expenditures, distribution objectives and similar
requirements.
Risk
Management Policy
We have established a comprehensive risk management policy, or
Risk Management Policy, and a risk management committee, or the
Risk Management Committee, to monitor and manage market risks
associated with commodity prices and counterparty credit. Our
Risk Management Committee is composed of senior executives who
receive regular briefings on positions and exposures, credit
exposures and overall risk management in the context of market
activities. The Risk Management Committee is responsible for the
overall management of credit risk and commodity price risk,
including monitoring exposure limits. Prior to the formation of
the Risk Management Committee, we were utilizing DCP Midstream,
LLCs risk management policies and procedures and risk
management committee to monitor and manage market risks.
See Note 2, Accounting for Risk Management Activities and
Financial Instruments, of the Notes to Consolidated Financial
Statements in Item 8. Financial Statements and
Supplementary Data for further discussion of the
accounting for derivative contracts.
Credit
Risk
Our principal customers in the Natural Gas Services segment are
large, natural gas marketing servicers and industrial end-users.
Our principal customers in the Wholesale Propane Logistics
segment are primarily retail propane distributors. In the NGL
Logistics Segment, our principal customers include an affiliate
of DCP Midstream, LLC, producers and marketing companies.
Substantially all of our natural gas, propane and NGL sales are
made at market-based prices. This concentration of credit risk
may affect our overall credit risk, as these customers may be
similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, we analyze the
counterparties financial condition prior to entering into
an agreement, establish credit limits, and monitor the
appropriateness of these limits on an ongoing basis. We operate
under DCP Midstream, LLCs corporate credit policy. DCP
Midstream, LLCs corporate credit policy, as well as the
standard terms and conditions of our agreements, prescribe the
use of financial responsibility and reasonable grounds for
adequate assurances. These provisions allow our credit
department to request that a counterparty remedy credit limit
violations by posting cash or letters of credit for exposure in
excess of an established credit line. The credit line represents
an open credit limit, determined in accordance with DCP
Midstream, LLCs credit policy. Our standard agreements
also provide that the inability of a counterparty to post
collateral is sufficient cause to terminate a contract and
liquidate all positions. The adequate assurance provisions also
94
allow us to suspend deliveries, cancel agreements or continue
deliveries to the buyer after the buyer provides security for
payment to us in a satisfactory form.
Interest
Rate Risk
Interest rates on future credit facility draws and debt
offerings could be higher than current levels, causing our
financing costs to increase accordingly. Although this could
limit our ability to raise funds in the debt capital markets, we
expect to remain competitive with respect to acquisitions and
capital projects, as our competitors would face similar
circumstances.
We mitigate a portion of our interest rate risk with interest
rate swaps, which reduce our exposure to market rate
fluctuations by converting variable interest rates to fixed
interest rates. These interest rate swap agreements convert the
interest rate associated with an aggregate of
$575.0 million of the indebtedness outstanding under our
revolving credit facility to a fixed rate obligation, thereby
reducing the exposure to market rate fluctuations. The interest
rate swap agreements have been designated as cash flow hedges,
and effectiveness is determined by matching the principal
balance and terms with that of the specified obligation. At
December 31, 2008, the effective weighted-average interest
rate on our $596.5 million of outstanding revolver debt was
4.48%, taking into account the $575.0 million of
indebtedness with designated interest rate swaps.
Based on the annualized unhedged borrowings under our credit
facility of $81.5 million as of December 31, 2008, a
0.5% movement in the base rate or LIBOR rate would result in an
approximately $0.4 million annualized increase or decrease
in interest expense.
Commodity
Price Risk
We are exposed to the impact of market fluctuations in the
prices of natural gas, NGLs and condensate as a result of our
gathering, processing, and sales activities. For gathering
services, we receive fees or commodities from producers to bring
the natural gas from the wellhead to the processing plant. For
processing services, we either receive fees or commodities as
payment for these services, depending on the types of contracts.
We employ established policies and procedures to manage our
risks associated with these market fluctuations using various
commodity derivatives, including forward contracts, swaps and
futures.
Commodity Cash Flow Protection Activities We
closely monitor the risks associated with commodity price
changes on our future operations and, where appropriate, use
various commodity instruments such as fixed price natural gas
and crude oil contracts to mitigate the effect pricing
fluctuations may have on the value of our assets and operations.
We enter into derivative financial instruments to mitigate the
risk of weakening natural gas, NGL and condensate prices
associated with our percent-of-proceeds arrangements and
gathering operations. Historically, there has been a strong
correlation between NGL prices and crude oil prices and lack of
liquidity in the NGL financial market; therefore we have
historically used crude oil swaps to mitigate NGL price risk. As
a result of these transactions, we have mitigated a significant
portion of our expected natural gas, NGL and condensate
commodity price risk through 2013.
The derivative financial instruments we have entered into are
typically referred to as swap contracts. These swap
contracts entitle us to receive payment at settlement from the
counterparty to the contract to the extent that the reference
price is below the swap price stated in the contract, and we are
required to make payment at settlement to the counterparty to
the extent that the reference price is higher than the swap
price stated in the contract.
Effective July 1, 2007, we elected to discontinue using the
hedge method of accounting for our commodity cash flow
protection activities. We are using the mark-to-market method of
accounting for all commodity derivative instruments, which has
significantly increased the volatility of our results of
operations as we recognize, in current earnings, all non-cash
gains and losses from the mark-to-market on derivative activity.
95
The following table sets forth additional information about our
fixed price natural gas and crude oil swaps used to mitigate our
natural gas and NGL price risk associated with our
percent-of-proceeds arrangements and our condensate price risk
associated with our gathering operations:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
Period
|
|
Commodity
|
|
Notional Volume
|
|
Reference Price
|
|
Price Range
|
|
January 2009 December 2009
|
|
Natural Gas
|
|
2,000 MMBtu/d
|
|
Texas Gas Transmission Price(a)
|
|
$9.20/MMBtu
|
January 2010 December 2010
|
|
Natural Gas
|
|
1,900 MMBtu/d
|
|
Texas Gas Transmission Price(a)
|
|
$9.20/MMBtu
|
January 2009 December 2013
|
|
Natural Gas
|
|
1,500 MMBtu/d
|
|
NYMEX Final Settlement Price(b)
|
|
$8.22/MMBtu
|
January 2009 December 2013
|
|
Natural Gas Basis
|
|
1,500 MMBtu/d
|
|
IFERC Monthly Index Price for
|
|
NYMEX less
|
|
|
|
|
|
|
Panhandle Eastern Pipe Line(c)
|
|
$0.68/MMBtu
|
January 2009 December 2009
|
|
Crude Oil
|
|
2,450 Bbls/d
|
|
Asian-pricing of NYMEX crude oil futures(d)
|
|
$63.05 - $86.95/Bbl
|
January 2010 December 2010
|
|
Crude Oil
|
|
2,415 Bbls/d
|
|
Asian-pricing of NYMEX crude oil futures(d)
|
|
$63.05 - $87.25/Bbl
|
January 2011 December 2011
|
|
Crude Oil
|
|
2,350 Bbls/d
|
|
Asian-pricing of NYMEX crude oil futures(d)
|
|
$66.72 - $87.25/Bbl
|
January 2012 December 2012
|
|
Crude Oil
|
|
2,325 Bbls/d
|
|
Asian-pricing of NYMEX crude oil futures(d)
|
|
$66.72 - $90.00/Bbl
|
January 2013 December 2013
|
|
Crude Oil
|
|
1,250 Bbls/d
|
|
Asian-pricing of NYMEX crude oil futures(d)
|
|
$67.60 - $71.20/Bbl
|
March 2009 December 2010(f)
|
|
Natural Gas
|
|
1,634 MMBtu/d
|
|
IFERC Monthly Index Price for
Colorado Interstate Gas Pipeline(e)
|
|
$3.94/MMBtu
|
April 2010 December 2011(f)
|
|
Crude Oil
|
|
250 Bbls/d
|
|
Asian-pricing of NYMBEX crude oil futures(d)
|
|
$56.75 - $59.30/Bbl
|
|
|
|
(a) |
|
The Inside FERC index price for natural gas delivered into the
Texas Gas Transmission pipeline in the North Louisiana area. |
|
(b) |
|
NYMEX final settlement price for natural gas futures contracts
(NG). |
|
(c) |
|
The Inside FERC monthly published index price for Panhandle
Eastern Pipe Line (Texas, Oklahoma mainline) less
the NYMEX final settlement price for natural gas futures
contracts. |
|
(d) |
|
Monthly average of the daily close prices for the prompt month
NYMEX light, sweet crude oil futures contract (CL). |
|
(e) |
|
The Inside FERC index price for natural gas delivered into the
Colorado Interstate Gas (CIG) pipeline. |
|
(f) |
|
These trades were entered into subsequent to December 31,
2008. |
At December 31, 2008, the aggregate fair value of the fixed
price natural gas and crude oil swaps described above was a net
gain of $6.5 million and $13.5 million respectively.
We utilize crude oil derivatives to mitigate a significant
portion of our commodity price exposure for propane and heavier
NGLs. Due to current movements in the relationship of NGL prices
to crude oil prices outside of recent historical ranges, we have
provided an additional sensitivity factor to capture movements
up or down in this relationship. We have combined the NGL and
crude oil sensitivities into one factor, and added our
sensitivity to changes in the relationship between the pricing
of NGLs and crude oil. For fixed price natural gas and crude
oil, the sensitivities are associated with our unhedged volumes.
For our NGL to crude oil price relationship, the sensitivity is
associated with both hedged and unhedged equity volumes. Given
our current contract mix and the commodity derivative contracts
we have in place, we have updated our annualized sensitivities
for 2009 as shown in the table below, which excludes the impact
from mark-to-market on our commodity derivatives.
Commodity
Sensitivities Excluding Non-Cash Mark-To-Market
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
Decrease in
|
|
|
|
|
|
|
|
|
|
Annual Net
|
|
|
|
Per Unit Decrease
|
|
|
Unit of Measurement
|
|
|
Income
|
|
|
|
|
|
|
|
|
|
(Millions)
|
|
|
Natural gas prices
|
|
$
|
1.00
|
|
|
|
MMBtu
|
|
|
$
|
0.3
|
|
Crude oil prices(a)
|
|
$
|
5.00
|
|
|
|
Barrel
|
|
|
$
|
1.7
|
|
NGL to crude oil price relationship(b)
|
|
|
5 percentage
point change
|
|
|
|
Barrel
|
|
|
$
|
4.6
|
|
96
|
|
|
(a) |
|
Assuming 60% NGL to crude oil price relationship. |
|
(b) |
|
Assuming 60% NGL to crude oil price relationship and $60.00/Bbl
crude oil price. Generally, this sensitivity changes by
$1.5 million for each $20.00/Bbl change in the price of
crude oil. As crude oil prices increase from $60.00/Bbl, we
become slightly more sensitive to the change in the relationship
of NGL prices to crude oil prices. As crude oil prices decrease
from $60.00/Bbl, we become less sensitive to the change in the
relationship of NGL prices to crude oil prices. |
In addition to the linear relationships in our commodity
sensitivities above, additional factors cause us to be less
sensitive to commodity price declines. A portion of our net
income is derived from fee-based contracts and a certain
percentage of liquids processing arrangements that contain
minimum fee clauses in which our processing margins convert to
fee-based arrangements as NGL prices decline.
The above sensitivities exclude the impact from arrangements
where producers on a monthly basis may elect to not process
their natural gas in which case we retain a portion of the
customers natural gas in lieu of NGLs as a fee. The above
sensitivities also exclude certain related processing
arrangements where we control the processing or by-pass of the
production based upon individual economic processing conditions.
Under each of these types of arrangements, our processing of the
natural gas would yield favorable processing margins. Less than
10% of our gas throughput is associated with these arrangements.
We estimate the following non-cash sensitivities in 2009 related
to the mark-to-market on our commodity derivatives associated
with our commodity cash flow protection activities:
Non-Cash
Mark-To-Market Commodity Sensitivities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
Mark-to-Market
|
|
|
|
|
|
|
|
|
|
Impact
|
|
|
|
|
|
|
|
|
|
(Decrease in
|
|
|
|
Per Unit Increase
|
|
|
Unit of Measurement
|
|
|
Net Income)
|
|
|
|
|
|
|
|
|
|
(Millions)
|
|
|
Natural gas prices
|
|
$
|
1.00
|
|
|
|
MMBtu
|
|
|
$
|
4.9
|
|
Crude oil prices
|
|
$
|
5.00
|
|
|
|
Barrel
|
|
|
$
|
18.8
|
|
While the above commodity price sensitivities are indicative of
the impact that changes in commodity prices may have on our
annualized net income, changes during certain periods of extreme
price volatility and market conditions or changes in the
correlation of the price of NGLs and crude oil may cause our
commodity price sensitivities to vary significantly from these
estimates.
The midstream natural gas industry is cyclical, with the
operating results of companies in the industry significantly
affected by the prevailing price of NGLs, which in turn has been
generally correlated to the price of crude oil, except in recent
periods, when NGL pricing has been at a greater discount to
crude oil pricing. Although the prevailing price of residue
natural gas has less short-term significance to our operating
results than the price of NGLs, in the long term the growth and
sustainability of our business depends on natural gas prices
being at levels sufficient to provide incentives and capital,
for producers to increase natural gas exploration and
production. The prices of NGLs, crude oil and natural gas can be
extremely volatile for periods of time, and may not always have
a close correlation. Changes in the correlation of the price of
NGLs and crude oil may cause our commodity price sensitivities
to vary. To minimize potential future commodity-based pricing
and cash flow volatility, we have entered into a series of
derivative financial instruments. As a result of these
transactions, we have mitigated a significant portion of our
expected natural gas, NGL and condensate commodity price risk
relating to the equity volumes associated with our gathering and
processing operations through 2013.
Based on historical trends, however, we generally expect NGL
prices to follow changes in crude oil prices over the long term,
which we believe will in large part be determined by the level
of production from major crude oil exporting countries and the
demand generated by growth in the world economy. We believe that
future natural gas prices will be influenced by supply
deliverability, the severity of winter and summer
97
weather, and the domestic production and drilling activity level
of exploration and production companies. Drilling activity can
be adversely affected as natural gas prices decrease. Energy
market uncertainty could also reduce North American drilling
activity in the future. Limited access to capital could also
decrease drilling. Lower drilling levels over a sustained period
would have a negative effect on natural gas volumes gathered and
processed, but would likely increase commodity prices.
Other Asset-Based Activities Our operations
of gathering, processing, and transporting natural gas, and the
accompanying operations of transporting and marketing of NGLs
create commodity price risk due to market fluctuations in
commodity prices, primarily with respect to the prices of NGLs,
natural gas and condensate. To the extent possible, we match the
pricing of our supply portfolio to our sales portfolio in order
to lock in value and reduce our overall commodity price risk. We
manage the commodity price risk of our supply portfolio and
sales portfolio with both physical and financial transactions.
We occasionally will enter into financial derivatives to lock in
price differentials across the Pelico system to maximize the
value of pipeline capacity.
Our wholesale propane logistics business is generally designed
to establish stable margins by entering into supply arrangements
that specify prices based on established floating price indices
and by entering into sales agreements that provide for floating
prices that are tied to our variable supply costs plus a margin.
Occasionally, we may enter into fixed price sales agreements in
the event that a retail propane distributor desires to purchase
propane from us on a fixed price basis. We manage this risk with
both physical and financial transactions, sometimes using
non-trading derivative instruments, which generally allow us to
swap our fixed price risk to market index prices that are
matched to our market index supply costs. In addition, we may on
occasion use financial derivatives to manage the value of our
propane inventories.
We manage our commodity derivative activities in accordance with
our Risk Management Policy which limits exposure to market risk
and requires regular reporting to management of potential
financial exposure.
Valuation Valuation of a contracts fair
value is validated by an internal group independent of the
marketing group. While common industry practices are used to
develop valuation techniques, changes in pricing methodologies
or the underlying assumptions could result in significantly
different fair values and income recognition. When available,
quoted market prices or prices obtained through external sources
are used to determine a contracts fair value. For
contracts with a delivery location or duration for which quoted
market prices are not available, fair value is determined based
on pricing models developed primarily from historical and
expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the
transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period
under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of
these contracts. Accordingly, it is reasonably possible that
such estimates may change in the near term.
The fair value of our interest rate swaps and commodity
non-trading derivatives is expected to be realized in future
periods, as detailed in the following table. The amount of cash
ultimately realized for these contracts will differ from the
amounts shown in the following table due to factors such as
market volatility, counterparty default and other unforeseen
events that could impact the amount
and/or
realization of these values.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity in
|
|
|
|
|
|
|
Maturity in
|
|
|
Maturity in
|
|
|
Maturity in
|
|
|
2014 and
|
|
Sources of Fair Value
|
|
Total
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
Thereafter
|
|
|
|
(Millions)
|
|
|
Prices supported by quoted market prices and other external
sources
|
|
$
|
(21.7
|
)
|
|
$
|
(2.6
|
)
|
|
$
|
(15.1
|
)
|
|
$
|
(4.0
|
)
|
|
$
|
|
|
Prices based on models or other valuation techniques
|
|
|
2.0
|
|
|
|
0.3
|
|
|
|
1.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(19.7
|
)
|
|
$
|
(2.3
|
)
|
|
$
|
(13.4
|
)
|
|
$
|
(4.0
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98
The prices supported by quoted market prices and other
external sources category includes our interest rate
swaps, our New York Mercantile Exchange, or NYMEX, swap
positions in natural gas, NGLs and our Asian-pricing NYMEX crude
oil swaps, for which our fair value is based upon unadjusted
quoted market prices for identical assets or liabilities in
active markets. In addition, this category includes our forward
positions in natural gas basis swaps for which our forward price
curves are obtained from SunGard Kiodex and then validated
through an internal process which includes the use of
independent broker quotes. This category also includes our
forward positions in NGLs at points for which over-the-counter,
or OTC, broker quotes for similar assets or liabilities are
available for the full term of the instrument. This category
also includes strip transactions whose pricing
inputs are directly or indirectly observable from external
sources and then modeled to daily or monthly prices as
appropriate.
The prices based on models and other valuation
methods category includes the value of transactions for
which inputs to the fair value of the instrument are
unobservable in the marketplace and are considered significant
to the overall fair value of the instrument. The fair value of
these instruments may be based upon an internally developed
price curve, which was constructed as a result of the long dated
nature of the transaction or the illiquidity of the market point.
99
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL
STATEMENTS:
|
|
|
|
|
|
|
|
101
|
|
|
|
|
102
|
|
|
|
|
103
|
|
|
|
|
104
|
|
|
|
|
105
|
|
|
|
|
106
|
|
|
|
|
107
|
|
100
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream Partners GP, LLC
Denver, Colorado:
We have audited the accompanying consolidated balance sheets of
DCP Midstream Partners, LP and subsidiaries (the
Company) as of December 31, 2008 and 2007, and
the related consolidated statements of operations, comprehensive
income (loss), changes in partners equity, and cash flows
for each of the three years in the period ended
December 31, 2008. Our audits also included the financial
statement schedule listed in the Index at Item 15. These
financial statements and financial statement schedule are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We did not audit the financial statements of Discovery Producer
Services, LLC (Discovery), an investment of the
Company which is accounted for by the use of the equity method.
The Companys equity in Discoverys net assets of
$145,054,000 and $161,519,000 at December 31, 2008 and
2007, respectively, and in Discoverys net income of
$13,760,000, $19,229,000, and $12,033,000 for the years ended
December 31, 2008, 2007 and 2006, respectively, are
included in the accompanying consolidated financial statements.
Discoverys financial statements were audited by other
auditors whose report has been furnished to us, and our opinion,
insofar as it relates to amounts included for Discovery, is
based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits and the
report of the other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and the report of the other
auditors, the consolidated financial statements present fairly,
in all material respects, the financial position of the Company
as of December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule
when considered with the basic consolidated financial statements
taken as a whole, presents fairly, in all material respects, the
information set forth therein.
As described in Note 1 to the consolidated financial
statements, through November 1, 2006, the portion of the
accompanying consolidated financial statements attributable to
the wholesale propane logistics business, have been prepared
from the separate records maintained by DCP Midstream, LLC
(Midstream) and may not necessarily be indicative of
the conditions that would have existed or the results of
operations if the wholesale propane logistics business had been
operated as an unaffiliated entity. Portions of certain expenses
represent allocations made from, and are applicable to Midstream
as a whole.
Also as described in Note 1 to the consolidated financial
statements through July 1, 2007, the portion of the
accompanying consolidated financial statements attributable to
DCP East Texas Holdings, LLC (East Texas) ,
Discovery and a nontrading derivative instrument (the
Swap) have been prepared from the separate records
maintained by Midstream and may not necessarily be indicative of
the conditions that would have existed or the results of
operations if East Texas, Discovery and the Swap had been
operated as unaffiliated entities. Portions of certain expenses
represent allocations made from, and are applicable to Midstream
as a whole.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2008, based on the criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated March 4, 2009 expressed an
unqualified opinion on the Companys internal control over
financial reporting.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 4, 2009
101
DCP
MIDSTREAM PARTNERS, LP
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
48.0
|
|
|
$
|
24.5
|
|
Short-term investments
|
|
|
|
|
|
|
1.3
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, net of allowance for doubtful accounts of
$0.6 million and $1.2 million, respectively
|
|
|
43.6
|
|
|
|
81.7
|
|
Affiliates
|
|
|
36.8
|
|
|
|
52.1
|
|
Inventories
|
|
|
20.9
|
|
|
|
37.3
|
|
Unrealized gains on derivative instruments
|
|
|
15.4
|
|
|
|
3.1
|
|
Other
|
|
|
0.5
|
|
|
|
18.5
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
165.2
|
|
|
|
218.5
|
|
Restricted investments
|
|
|
60.2
|
|
|
|
100.5
|
|
Property, plant and equipment, net
|
|
|
629.3
|
|
|
|
500.7
|
|
Goodwill
|
|
|
88.8
|
|
|
|
80.2
|
|
Intangible assets, net
|
|
|
47.7
|
|
|
|
29.7
|
|
Equity method investments
|
|
|
175.4
|
|
|
|
187.2
|
|
Unrealized gains on derivative instruments
|
|
|
8.6
|
|
|
|
2.7
|
|
Other long-term assets
|
|
|
4.8
|
|
|
|
1.2
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,180.0
|
|
|
$
|
1,120.7
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
44.8
|
|
|
$
|
110.2
|
|
Affiliates
|
|
|
33.6
|
|
|
|
55.6
|
|
Unrealized losses on derivative instruments
|
|
|
17.7
|
|
|
|
30.9
|
|
Accrued interest payable
|
|
|
1.3
|
|
|
|
1.6
|
|
Other
|
|
|
27.4
|
|
|
|
21.3
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
124.8
|
|
|
|
219.6
|
|
Long-term debt
|
|
|
656.5
|
|
|
|
630.0
|
|
Unrealized losses on derivative instruments
|
|
|
26.0
|
|
|
|
70.0
|
|
Other long-term liabilities
|
|
|
8.9
|
|
|
|
5.8
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
816.2
|
|
|
|
925.4
|
|
|
|
|
|
|
|
|
|
|
Non-controlling interests
|
|
|
34.7
|
|
|
|
26.9
|
|
Commitments and contingent liabilities
|
|
|
|
|
|
|
|
|
Partners equity:
|
|
|
|
|
|
|
|
|
Common unitholders (24,661,754 and 16,840,326 units issued
and outstanding, respectively)
|
|
|
429.0
|
|
|
|
308.8
|
|
Subordinated unitholders (3,571,429 and 7,142,857 convertible
units issued and outstanding, respectively)
|
|
|
(54.6
|
)
|
|
|
(120.1
|
)
|
General partner interest
|
|
|
(4.8
|
)
|
|
|
(5.4
|
)
|
Accumulated other comprehensive loss
|
|
|
(40.5
|
)
|
|
|
(14.9
|
)
|
|
|
|
|
|
|
|
|
|
Total partners equity
|
|
|
329.1
|
|
|
|
168.4
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity
|
|
$
|
1,180.0
|
|
|
$
|
1,120.7
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
102
DCP
MIDSTREAM PARTNERS, LP
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions, except per unit amounts)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, propane, NGLs and condensate
|
|
$
|
678.5
|
|
|
$
|
628.1
|
|
|
$
|
535.1
|
|
Sales of natural gas, propane, NGLs and condensate to affiliates
|
|
|
477.8
|
|
|
|
297.7
|
|
|
|
232.8
|
|
Transportation, processing and other
|
|
|
31.2
|
|
|
|
18.5
|
|
|
|
15.0
|
|
Transportation, processing and other to affiliates
|
|
|
26.0
|
|
|
|
16.6
|
|
|
|
12.8
|
|
Gains (losses) from commodity derivative activity, net
|
|
|
75.4
|
|
|
|
(83.1
|
)
|
|
|
|
|
(Losses) gains from commodity derivative activity,
net affiliates
|
|
|
(3.1
|
)
|
|
|
(4.5
|
)
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,285.8
|
|
|
|
873.3
|
|
|
|
795.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas, propane and NGLs
|
|
|
798.3
|
|
|
|
647.4
|
|
|
|
581.2
|
|
Purchases of natural gas, propane and NGLs from affiliates
|
|
|
262.9
|
|
|
|
179.3
|
|
|
|
119.2
|
|
Operating and maintenance expense
|
|
|
43.0
|
|
|
|
32.1
|
|
|
|
23.7
|
|
Depreciation and amortization expense
|
|
|
36.5
|
|
|
|
24.4
|
|
|
|
12.8
|
|
General and administrative expense
|
|
|
12.4
|
|
|
|
14.1
|
|
|
|
12.9
|
|
General and administrative expense affiliates
|
|
|
11.6
|
|
|
|
10.0
|
|
|
|
8.1
|
|
Other
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,163.2
|
|
|
|
907.3
|
|
|
|
757.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
122.6
|
|
|
|
(34.0
|
)
|
|
|
37.9
|
|
Interest income
|
|
|
5.6
|
|
|
|
5.3
|
|
|
|
6.3
|
|
Interest expense
|
|
|
(32.8
|
)
|
|
|
(25.8
|
)
|
|
|
(11.5
|
)
|
Earnings from equity method investments
|
|
|
34.3
|
|
|
|
39.3
|
|
|
|
29.2
|
|
Non-controlling interest in income
|
|
|
(3.9
|
)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
125.8
|
|
|
|
(15.7
|
)
|
|
|
61.9
|
|
Income tax expense
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to predecessor operations
|
|
|
|
|
|
|
(3.6
|
)
|
|
|
(26.6
|
)
|
General partner interest in net income
|
|
|
(11.9
|
)
|
|
|
(2.2
|
)
|
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to limited partners
|
|
$
|
113.8
|
|
|
$
|
(21.6
|
)
|
|
$
|
34.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit basic and
diluted
|
|
$
|
3.25
|
|
|
$
|
(1.05
|
)
|
|
$
|
1.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average limited partner units outstanding
basic and diluted
|
|
|
27.4
|
|
|
|
20.5
|
|
|
|
17.5
|
|
See accompanying notes to consolidated financial statements.
103
DCP
MIDSTREAM PARTNERS, LP
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification of cash flow hedges into earnings
|
|
|
7.5
|
|
|
|
(3.1
|
)
|
|
|
(2.7
|
)
|
Net unrealized (losses) gains on cash flow hedges
|
|
|
(33.1
|
)
|
|
|
(19.1
|
)
|
|
|
9.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive (loss) income
|
|
|
(25.6
|
)
|
|
|
(22.2
|
)
|
|
|
6.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss)
|
|
$
|
100.1
|
|
|
$
|
(38.0
|
)
|
|
$
|
68.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
104
DCP
MIDSTREAM PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CHANGES IN PARTNERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
|
|
|
Other
|
|
|
Total
|
|
|
|
Predecessor
|
|
|
Common
|
|
|
Class C
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Comprehensive
|
|
|
Partners
|
|
|
|
Equity
|
|
|
Unitholders
|
|
|
Unitholders
|
|
|
Unitholders
|
|
|
Interest
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
(Millions)
|
|
|
Balance, January 1, 2006
|
|
$
|
219.8
|
|
|
$
|
215.8
|
|
|
$
|
|
|
|
$
|
(109.7
|
)
|
|
$
|
(5.6
|
)
|
|
$
|
0.4
|
|
|
$
|
320.7
|
|
Net change in parent advances
|
|
|
(25.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25.4
|
)
|
Acquisition of wholesale propane logistics business
|
|
|
(56.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(56.7
|
)
|
Excess purchase price over acquired assets
|
|
|
|
|
|
|
|
|
|
|
(26.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26.3
|
)
|
Issuance of 200,312 Class C units
|
|
|
|
|
|
|
|
|
|
|
5.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.6
|
|
Proceeds from general partner interest (represented by 4,088
equivalent units)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
0.1
|
|
Contributions by unitholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.8
|
|
|
|
0.2
|
|
|
|
|
|
|
|
3.0
|
|
Distributions to unitholders
|
|
|
|
|
|
|
(12.8
|
)
|
|
|
(0.1
|
)
|
|
|
(8.8
|
)
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
(22.1
|
)
|
Net income attributable to predecessor operations
|
|
|
26.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26.6
|
|
Net income
|
|
|
|
|
|
|
20.4
|
|
|
|
0.1
|
|
|
|
14.1
|
|
|
|
0.7
|
|
|
|
|
|
|
|
35.3
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.9
|
|
|
|
6.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
164.3
|
|
|
|
223.4
|
|
|
|
(20.7
|
)
|
|
|
(101.6
|
)
|
|
|
(5.0
|
)
|
|
|
7.3
|
|
|
|
267.7
|
|
Net change in parent advances
|
|
|
(14.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14.6
|
)
|
Acquisition of East Texas, Discovery and the Swap
|
|
|
(153.3
|
)
|
|
|
27.0
|
|
|
|
|
|
|
|
|
|
|
|
0.6
|
|
|
|
|
|
|
|
(125.7
|
)
|
Excess purchase price over acquired assets
|
|
|
|
|
|
|
(118.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(118.0
|
)
|
Acquisition of Momentum Energy Group, Inc.
|
|
|
|
|
|
|
12.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.0
|
|
Purchase of units
|
|
|
|
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.3
|
)
|
Issuance of units
|
|
|
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.3
|
|
Issuance of 5,386,732 common units
|
|
|
|
|
|
|
228.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
228.5
|
|
Conversion of Class C units to common units
|
|
|
|
|
|
|
(20.7
|
)
|
|
|
20.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions by unitholders
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
0.8
|
|
Distributions to unitholders
|
|
|
|
|
|
|
(27.0
|
)
|
|
|
(0.2
|
)
|
|
|
(14.1
|
)
|
|
|
(3.2
|
)
|
|
|
|
|
|
|
(44.5
|
)
|
Equity-based compensation
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2
|
|
Net income attributable to predecessor operations
|
|
|
3.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.6
|
|
Net income (loss)
|
|
|
|
|
|
|
(16.8
|
)
|
|
|
0.2
|
|
|
|
(5.0
|
)
|
|
|
2.2
|
|
|
|
|
|
|
|
(19.4
|
)
|
Other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22.2
|
)
|
|
|
(22.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
|
|
|
|
308.8
|
|
|
|
|
|
|
|
(120.1
|
)
|
|
|
(5.4
|
)
|
|
|
(14.9
|
)
|
|
|
168.4
|
|
Issuance of 4,250,000 common units
|
|
|
|
|
|
|
132.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132.1
|
|
Conversion of subordinated units to common units
|
|
|
|
|
|
|
(66.4
|
)
|
|
|
|
|
|
|
66.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions by unitholders
|
|
|
|
|
|
|
4.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.0
|
|
Distributions to unitholders and general partner
|
|
|
|
|
|
|
(53.9
|
)
|
|
|
|
|
|
|
(10.5
|
)
|
|
|
(11.3
|
)
|
|
|
|
|
|
|
(75.7
|
)
|
Equity-based compensation
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2
|
|
Net income
|
|
|
|
|
|
|
104.2
|
|
|
|
|
|
|
|
9.6
|
|
|
|
11.9
|
|
|
|
|
|
|
|
125.7
|
|
Other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25.6
|
)
|
|
|
(25.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
$
|
|
|
|
$
|
429.0
|
|
|
$
|
|
|
|
$
|
(54.6
|
)
|
|
$
|
(4.8
|
)
|
|
$
|
(40.5
|
)
|
|
$
|
329.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
105
DCP
MIDSTREAM PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
36.5
|
|
|
|
24.4
|
|
|
|
12.8
|
|
Earnings from equity method investments, net of distributions
|
|
|
25.6
|
|
|
|
(0.4
|
)
|
|
|
(3.3
|
)
|
Non-controlling interest in income
|
|
|
3.9
|
|
|
|
0.5
|
|
|
|
|
|
Other, net
|
|
|
(0.4
|
)
|
|
|
(0.2
|
)
|
|
|
(2.4
|
)
|
Change in operating assets and liabilities which provided (used)
cash, net of effects of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
55.4
|
|
|
|
(42.2
|
)
|
|
|
43.1
|
|
Inventories
|
|
|
16.4
|
|
|
|
(7.2
|
)
|
|
|
11.6
|
|
Net unrealized (gains) losses on derivative instruments
|
|
|
(101.0
|
)
|
|
|
81.1
|
|
|
|
(0.1
|
)
|
Accounts payable
|
|
|
(79.7
|
)
|
|
|
38.9
|
|
|
|
(31.5
|
)
|
Accrued interest
|
|
|
(0.3
|
)
|
|
|
0.5
|
|
|
|
0.3
|
|
Other current assets and liabilities
|
|
|
19.8
|
|
|
|
(16.4
|
)
|
|
|
2.0
|
|
Other long-term assets and liabilities
|
|
|
(0.4
|
)
|
|
|
2.2
|
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
101.5
|
|
|
|
65.4
|
|
|
|
94.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(41.0
|
)
|
|
|
(21.3
|
)
|
|
|
(27.2
|
)
|
Acquisition of Michigan Pipeline & Processing, LLC,
net of cash acquired
|
|
|
(146.4
|
)
|
|
|
|
|
|
|
|
|
Acquisition of subsidiaries of Momentum Energy Group, Inc., net
of cash acquired
|
|
|
(10.9
|
)
|
|
|
(142.0
|
)
|
|
|
|
|
Acquisition of assets
|
|
|
|
|
|
|
(191.3
|
)
|
|
|
|
|
Acquisition of equity method investments
|
|
|
|
|
|
|
(153.3
|
)
|
|
|
|
|
Investments in equity method investments
|
|
|
(13.8
|
)
|
|
|
(16.3
|
)
|
|
|
(11.1
|
)
|
Payment of earnest deposit
|
|
|
|
|
|
|
(9.0
|
)
|
|
|
|
|
Refund of earnest deposit
|
|
|
|
|
|
|
9.0
|
|
|
|
|
|
Acquisition of wholesale propane logistics business
|
|
|
|
|
|
|
|
|
|
|
(56.7
|
)
|
Proceeds from sales of assets
|
|
|
2.9
|
|
|
|
0.1
|
|
|
|
0.3
|
|
Purchases of available-for-sale securities
|
|
|
(608.2
|
)
|
|
|
(6,921.6
|
)
|
|
|
(7,372.4
|
)
|
Proceeds from sales of available-for-sale securities
|
|
|
650.5
|
|
|
|
6,924.0
|
|
|
|
7,373.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(166.9
|
)
|
|
|
(521.7
|
)
|
|
|
(93.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
660.4
|
|
|
|
579.0
|
|
|
|
78.0
|
|
Payments of debt
|
|
|
(633.9
|
)
|
|
|
(217.0
|
)
|
|
|
(20.1
|
)
|
Payment of deferred financing costs
|
|
|
|
|
|
|
(0.6
|
)
|
|
|
(0.2
|
)
|
Purchase of units
|
|
|
|
|
|
|
(0.3
|
)
|
|
|
|
|
Proceeds from issuance of common units, net of offering costs
|
|
|
132.1
|
|
|
|
228.5
|
|
|
|
|
|
Proceeds from issuance of equivalent units to general partner
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
Excess purchase price over acquired assets
|
|
|
|
|
|
|
(100.3
|
)
|
|
|
(10.7
|
)
|
Net change in advances from DCP Midstream, LLC
|
|
|
|
|
|
|
(14.6
|
)
|
|
|
(25.4
|
)
|
Distributions to unitholders and general partner
|
|
|
(76.2
|
)
|
|
|
(44.0
|
)
|
|
|
(22.1
|
)
|
Distributions to non-controlling interests
|
|
|
(3.3
|
)
|
|
|
|
|
|
|
|
|
Contributions from non-controlling interests
|
|
|
5.7
|
|
|
|
3.4
|
|
|
|
|
|
Contributions from DCP Midstream, LLC
|
|
|
4.1
|
|
|
|
0.5
|
|
|
|
3.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
88.9
|
|
|
|
434.6
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
23.5
|
|
|
|
(21.7
|
)
|
|
|
4.0
|
|
Cash and cash equivalents, beginning of period
|
|
|
24.5
|
|
|
|
46.2
|
|
|
|
42.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
48.0
|
|
|
$
|
24.5
|
|
|
$
|
46.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
106
DCP
MIDSTREAM PARTNERS, LP
Years
Ended December 31, 2008, 2007 and 2006
|
|
1.
|
Description
of Business and Basis of Presentation
|
DCP Midstream Partners, LP, with its consolidated subsidiaries,
or us, we or our, is engaged in the business of gathering,
compressing, treating, processing, transporting and selling
natural gas, producing, transporting, storing and selling
propane and transporting and selling NGLs and condensate.
We are a Delaware master limited partnership that was formed in
August 2005. We completed our initial public offering on
December 7, 2005. Our partnership includes: our Northern
Louisiana system; our Southern Oklahoma system (acquired in May
2007); our limited liability company interests in DCP East Texas
Holdings, LLC, or East Texas, and Discovery Producer Services
LLC, or Discovery (acquired in July 2007); our Wyoming system
and a 70% interest in our Colorado system (each acquired in
August 2007); our Michigan systems (acquired in October 2008);
our wholesale propane logistics business (acquired in November
2006); and our NGL transportation pipelines.
Our operations and activities are managed by our general
partner, DCP Midstream GP, LP, which in turn is managed by its
general partner, DCP Midstream GP, LLC, which we refer to as the
General Partner, which is wholly-owned by DCP Midstream, LLC.
DCP Midstream, LLC and its subsidiaries and affiliates,
collectively referred to as DCP Midstream, LLC, is owned 50% by
Spectra Energy Corp, or Spectra Energy, and 50% by
ConocoPhillips. DCP Midstream, LLC directs our business
operations through its ownership and control of the General
Partner. DCP Midstream, LLC and its affiliates employees
provide administrative support to us and operate our assets. DCP
Midstream, LLC owns approximately 30% of our partnership.
The consolidated financial statements include our accounts, and
prior to December 7, 2005 the assets, liabilities and
operations contributed to us by DCP Midstream, LLC and its
wholly-owned subsidiaries, which we refer to as DCP Midstream
Partners Predecessor, upon the closing of our initial public
offering, which have been combined with the historical assets,
liabilities and operations of our wholesale propane logistics
business which we acquired from DCP Midstream, LLC in November
2006, and our 25% limited liability company interest in East
Texas, our 40% limited liability company interest in Discovery,
and a non-trading derivative instrument, or the Swap, which DCP
Midstream, LLC entered into in March 2007, which we acquired
from DCP Midstream, LLC in July 2007. These were transactions
among entities under common control. We recognize transfers of
net assets between entities under common control at DCP
Midstream, LLCs basis in the net assets contributed. In
addition, transfers of net assets between entities under common
control are accounted for as if the transfer occurred at the
beginning of the period, and prior years are retroactively
adjusted to furnish comparative information similar to the
pooling method; accordingly, our financial information includes
the historical results of our wholesale propane logistics
business, Discovery and East Texas for all periods presented.
The amount of the purchase price in excess of DCP Midstream,
LLCs basis in the net assets, if any, is recognized as a
reduction to partners equity. In addition, the results of
operations of our Southern Oklahoma, Wyoming and Colorado
systems, and our Michigan systems, have been included in the
consolidated financial statements since their respective
acquisition dates.
The consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the
United States of America, or GAAP. We refer to DCP Midstream
Partners Predecessor, the assets, liabilities and operations of
our wholesale propane logistics business, our equity interests
in East Texas and Discovery, and the Swap, prior to our
acquisition from DCP Midstream, LLC, collectively as our
predecessors. The consolidated financial statements
of our predecessors have been prepared from the separate records
maintained by DCP Midstream, LLC and may not necessarily be
indicative of the conditions that would have existed or the
results of operations if our predecessors had been operated as
an unaffiliated entity. All significant intercompany balances
and transactions have been eliminated. Transactions between us
and other DCP Midstream, LLC operations have been identified in
the consolidated financial statements as transactions between
affiliates.
107
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
2.
|
Summary
of Significant Accounting Policies
|
Use of Estimates Conformity with GAAP
requires management to make estimates and assumptions that
affect the amounts reported in the consolidated financial
statements and notes. Although these estimates are based on
managements best available knowledge of current and
expected future events, actual results could differ from those
estimates.
Cash and Cash Equivalents We consider
investments in highly liquid financial instruments purchased
with an original stated maturity of 90 days or less to be
cash equivalents.
Short-Term and Restricted Investments
We may invest available cash balances in
various financial instruments, such as commercial paper, money
market instruments and tax-exempt debt securities that have
stated maturities of 20 years or more. These instruments
provide for a high degree of liquidity through features, which
allow for the redemption of the investment at its face amount
plus earned income. As we generally intend to sell these
instruments within one year or less from the balance sheet date,
and as they are available for use in current operations, they
are classified as current assets, unless otherwise restricted.
Restricted investments are used as collateral to secure the term
loan portion of our credit facility and to finance gathering and
compression asset acquisitions. We have classified all
short-term and restricted investments as available-for-sale as
we do not intend to hold them to maturity, nor are they bought
or sold with the objective of generating profit on short-term
differences in prices. These investments are recorded at fair
value, with changes in fair value recorded as unrealized gains
and losses in accumulated other comprehensive income (loss), or
AOCI. The cost, including accrued interest on investments,
approximates fair value, due to the short-term, highly liquid
nature of the securities held by us, and as interest rates are
re-set on a daily, weekly or monthly basis.
Inventories Inventories, which consist
primarily of propane, are recorded at the lower of
weighted-average cost or market value. Transportation costs are
included in inventory.
Property, Plant and Equipment
Property, plant and equipment are recorded
at historical cost. The cost of maintenance and repairs, which
are not significant improvements, are expensed when incurred.
Depreciation is computed using the straight-line method over the
estimated useful lives of the assets.
Asset retirement obligations associated with tangible long-lived
assets are recorded at fair value in the period in which they
are incurred, if a reasonable estimate of fair value can be
made, and added to the carrying amount of the associated asset.
This additional carrying amount is then depreciated over the
life of the asset. The liability is determined using a risk free
interest rate, and increases due to the passage of time based on
the time value of money until the obligation is settled. We
recognize a liability of a conditional asset retirement
obligation as soon as the fair value of the liability can be
reasonably estimated. A conditional asset retirement obligation
is defined as an unconditional legal obligation to perform an
asset retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity.
Goodwill and Intangible Assets
Goodwill is the cost of an acquisition less
the fair value of the net assets of the acquired business. We
evaluate goodwill for impairment annually in the third quarter,
and whenever events or changes in circumstances indicate it is
more likely than not that the fair value of a reporting unit is
less than its carrying amount. Impairment testing of goodwill
consists of a two-step process. The first step involves
comparing the fair value of the reporting unit, to which
goodwill has been allocated, with its carrying amount. If the
carrying amount of the reporting unit exceeds its fair value,
the second step of the process involves comparing the fair value
and carrying value of the goodwill of that reporting unit. If
the carrying value of the goodwill of a reporting unit exceeds
the fair value of that goodwill, the excess of the carrying
value over the fair value is recognized as an impairment loss.
108
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Intangible assets consist primarily of customer contracts,
including commodity purchase, transportation and processing
contracts and related relationships. These intangible assets are
amortized on a straight-line basis over the period of expected
future benefit.
Long-Lived Assets We periodically
evaluate whether the carrying value of long-lived assets has
been impaired when circumstances indicate the carrying value of
those assets may not be recoverable. This evaluation is based on
undiscounted cash flow projections. The carrying amount is not
recoverable if it exceeds the sum of the undiscounted cash flows
expected to result from the use and eventual disposition of the
asset. We consider various factors when determining if these
assets should be evaluated for impairment, including but not
limited to:
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significant adverse change in legal factors or business climate;
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a current-period operating or cash flow loss combined with a
history of operating or cash flow losses, or a projection or
forecast that demonstrates continuing losses associated with the
use of a long-lived asset;
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an accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of a
long-lived asset;
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significant adverse changes in the extent or manner in which an
asset is used, or in its physical condition;
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a significant adverse change in the market value of an
asset; or
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a current expectation that, more likely than not, an asset will
be sold or otherwise disposed of before the end of its estimated
useful life.
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If the carrying value is not recoverable, the impairment loss is
measured as the excess of the assets carrying value over
its fair value. We assess the fair value of long-lived assets
using commonly accepted techniques, and may use more than one
method, including, but not limited to, recent third party
comparable sales and discounted cash flow models. Significant
changes in market conditions resulting from events such as the
condition of an asset or a change in managements intent to
utilize the asset would generally require management to reassess
the cash flows related to the long-lived assets.
Equity Method Investments We use the
equity method to account for investments in greater than 20%
owned affiliates that are not variable interest entities and
where we do not have the ability to exercise control, and
investments in less than 20% owned affiliates where we have the
ability to exercise significant influence.
We evaluate our equity method investments for impairment
whenever events or changes in circumstances indicate that the
carrying value of such investments may have experienced a
decline in value. When evidence of loss in value has occurred,
we compare the estimated fair value of the investment to the
carrying value of the investment to determine whether an
impairment has occurred. We assess the fair value of our equity
method investments using commonly accepted techniques, and may
use more than one method, including, but not limited to, recent
third party comparable sales and discounted cash flow models. If
the estimated fair value is less than the carrying value, the
excess of the carrying value over the estimated fair value is
recognized as an impairment loss.
Unamortized Debt Expense Expenses
incurred with the issuance of long-term debt are amortized over
the term of the debt using the effective interest method. These
expenses are recorded on the consolidated balance sheet as other
long-term assets.
Non-Controlling Interest
Non-controlling interest represents
(1) the non-controlling interest holders ownership
interests in the net assets of Collbran Valley Gas Gathering, a
joint venture acquired in conjunction with the MEG acquisition
in August 2007; and (2) the non controlling interest
holders portion of the net
109
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
assets of Jackson Pipeline Company, a partnership we acquired
with the Michigan acquisition in October 2008. For financial
reporting purposes, the assets and liabilities of these entities
are consolidated with those of our own, with any third party
interest in our consolidated balance sheet amounts shown as
non-controlling interest. Distributions to and contributions
from non-controlling interests represent cash payments and cash
contributions, respectively, from such third-party investors.
Accounting for Risk Management Activities and Financial
Instruments Effective July 1, 2007, we
elected to discontinue using the hedge method of accounting for
our commodity cash flow protection activities. We are using the
mark-to-market method of accounting for all commodity derivative
instruments beginning in July 2007. As a result, the remaining
net loss deferred in AOCI will be reclassified to sales of
natural gas, propane, NGLs and condensate, through December
2011, as the underlying transactions impact earnings.
Each derivative not qualifying for the normal purchases and
normal sales exception is recorded on a gross basis in the
consolidated balance sheets at its fair value as unrealized
gains or unrealized losses on derivative instruments. Derivative
assets and liabilities remain classified in our consolidated
balance sheets as unrealized gains or unrealized losses on
derivative instruments at fair value until the contractual
settlement period impacts earnings.
All derivative activity reflected in the consolidated financial
statements for our predecessors was transacted by us or by DCP
Midstream, LLC and its subsidiaries, and transferred
and/or
allocated to us. All derivative activity reflected in the
consolidated financial statements, which is not related to our
predecessors, has been and will be transacted by us. Prior to
July 1, 2007, we designated each energy commodity
derivative as either trading or non-trading. Certain non-trading
derivatives were further designated as either a hedge of a
forecasted transaction or future cash flow (cash flow hedge), a
hedge of a recognized asset, liability or firm commitment (fair
value hedge), or normal purchases or normal sales, while certain
non-trading derivatives, which are related to asset-based
activities, are designated as non-trading derivative activity.
For the periods presented, we did not have any trading
derivative activity, however, we did have cash flow and fair
value hedge activity, normal purchases and normal sales
activity, and non-trading derivative activity included in the
consolidated financial statements. For each derivative, the
accounting method and presentation of gains and losses or
revenue and expense in the consolidated statements of operations
are as follows:
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Classification of Contract
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Accounting Method
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Presentation of Gains & Losses or Revenue &
Expense
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Non-Trading Derivative Activity
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Mark-to-market method(b)
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Net basis in gains and losses from derivative activity
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Cash Flow Hedge(a)
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Hedge method(c)
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Gross basis in the same consolidated statements of operations
category as the related hedged item
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Fair Value Hedge(a)
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Hedge method(c)
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Gross basis in the same consolidated statements of operations
category as the related hedged item
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Normal Purchases or Normal Sales
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Accrual method(d)
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Gross basis upon settlement in the corresponding consolidated
statements of operations category based on purchase or sale
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(a) |
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Effective July 1, 2007, all commodity cash flow hedges are
classified as non-trading derivative activity. Our interest rate
swaps continue to be accounted for as cash flow hedges. As of
December 31, 2007 we no longer use fair value hedges. |
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(b) |
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Mark-to-market An accounting method whereby the
change in the fair value of the asset or liability is recognized
in the consolidated statements of operations in gains and losses
from derivative activity during the current period. |
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(c) |
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Hedge method An accounting method whereby the change
in the fair value of the asset or liability is recorded in the
consolidated balance sheets as unrealized gains or unrealized
losses on derivative instruments. For cash flow hedges, there is
no recognition in the consolidated statements of operations for
the |
110
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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effective portion until the service is provided or the
associated delivery period impacts earnings. For fair value
hedges, the change in the fair value of the asset or liability,
as well as the offsetting changes in value of the hedged item,
are recognized in the consolidated statements of operations in
the same category as the related hedged item. |
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(d) |
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Accrual method An accounting method whereby there is
no recognition in the consolidated balance sheets or
consolidated statements of operations for changes in fair value
of a contract until the service is provided or the associated
delivery period impacts earnings. |
Cash Flow and Fair Value Hedges For
derivatives designated as a cash flow hedge or a fair value
hedge, we maintain formal documentation of the hedge. In
addition, we formally assess both at the inception of the
hedging relationship and on an ongoing basis, whether the hedge
contract is highly effective in offsetting changes in cash flows
or fair values of hedged items. All components of each
derivative gain or loss are included in the assessment of hedge
effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge
is recorded in the consolidated balance sheets as unrealized
gains or unrealized losses on derivative instruments. The
effective portion of the change in fair value of a derivative
designated as a cash flow hedge is recorded in partners
equity as AOCI, and the ineffective portion is recorded in the
consolidated statements of operations. During the period in
which the hedged transaction impacts earnings, amounts in AOCI
associated with the hedged transaction are reclassified to the
consolidated statements of operations in the same accounts as
the item being hedged. Hedge accounting is discontinued
prospectively when it is determined that the derivative no
longer qualifies as an effective hedge, or when it is probable
that the hedged transaction will not occur. When hedge
accounting is discontinued because the derivative no longer
qualifies as an effective hedge, the derivative is subject to
the mark-to-market accounting method prospectively. The
derivative continues to be carried on the consolidated balance
sheets at its fair value; however, subsequent changes in its
fair value are recognized in current period earnings. Gains and
losses related to discontinued hedges that were previously
accumulated in AOCI will remain in AOCI until the hedged
transaction impacts earnings, unless it is probable that the
hedged transaction will not occur, in which case, the gains and
losses that were previously deferred in AOCI will be immediately
recognized in current period earnings.
The fair value of a derivative designated as a fair value hedge
is recorded for balance sheet purposes as unrealized gains or
unrealized losses on derivative instruments. We recognize the
gain or loss on the derivative instrument, as well as the
offsetting loss or gain on the hedged item in earnings in the
current period. All derivatives designated and accounted for as
fair value hedges are classified in the same category as the
item being hedged in the results of operations.
Valuation When available, quoted market
prices or prices obtained through external sources are used to
determine a contracts fair value. For contracts with a
delivery location or duration for which quoted market prices are
not available, fair value is determined based on pricing models
developed primarily from historical and expected correlations
with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the
transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period
under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of
these contracts. Accordingly, it is reasonably possible that
such estimates may change in the near term.
Revenue Recognition We generate the
majority of our revenues from gathering, processing,
compressing, transporting, and fractionating natural gas and
NGLs, and from trading and marketing of natural gas and NGLs. We
realize revenues either by selling the residue natural gas and
NGLs, or by receiving fees from the producers.
111
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We obtain access to commodities and provide our midstream
services principally under contracts that contain a combination
of one or more of the following arrangements:
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Fee-based arrangements Under fee-based
arrangements, we receive a fee or fees for one or more of the
following services: gathering, compressing, treating, processing
or transporting natural gas; and transporting NGLs. Our
fee-based arrangements include natural gas purchase arrangements
pursuant to which we purchase natural gas at the wellhead or
other receipt points, at an index related price at the delivery
point less a specified amount, generally the same as the
transportation fees we would otherwise charge for transportation
of natural gas from the wellhead location to the delivery point.
The revenues we earn are directly related to the volume of
natural gas or NGLs that flows through our systems and are not
directly dependent on commodity prices. However, to the extent a
sustained decline in commodity prices results in a decline in
volumes, our revenues from these arrangements would be reduced.
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Percent-of-proceeds arrangements Under
percent-of-proceeds arrangements, we generally purchase natural
gas from producers at the wellhead, or other receipt points,
gather the wellhead natural gas through our gathering system,
treat and process the natural gas, and then sell the resulting
residue natural gas and NGLs based on index prices from
published index market prices. We remit to the producers either
an
agreed-upon
percentage of the actual proceeds that we receive from our sales
of the residue natural gas and NGLs, or an
agreed-upon
percentage of the proceeds based on index related prices for the
natural gas and the NGLs, regardless of the actual amount of the
sales proceeds we receive. Certain of these arrangements may
also result in our returning all or a portion of the residue
natural gas
and/or the
NGLs to the producer, in lieu of returning sales proceeds. Our
revenues under percent-of-proceeds arrangements correlate
directly with the price of natural gas
and/or NGLs.
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Propane sales arrangements Under propane
sales arrangements, we generally purchase propane from natural
gas processing plants and fractionation facilities, and crude
oil refineries. We sell propane on a wholesale basis to retail
propane distributors, who in turn resell to their retail
customers. Our sales of propane are not contingent upon the
resale of propane by propane distributors to their retail
customers.
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Our marketing of natural gas and NGLs consists of physical
purchases and sales, as well as positions in derivative
instruments.
We recognize revenues for sales and services under the four
revenue recognition criteria, as follows:
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Persuasive evidence of an arrangement exists
Our customary practice is to enter into a
written contract, executed by both us and the customer.
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Delivery Delivery is deemed to have occurred
at the time custody is transferred, or in the case of fee-based
arrangements, when the services are rendered. To the extent we
retain product as inventory, delivery occurs when the inventory
is subsequently sold and custody is transferred to the third
party purchaser.
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The fee is fixed or determinable We negotiate
the fee for our services at the outset of our fee-based
arrangements. In these arrangements, the fees are nonrefundable.
For other arrangements, the amount of revenue, based on
contractual terms, is determinable when the sale of the
applicable product has been completed upon delivery and transfer
of custody.
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Collectibility is probable Collectibility is
evaluated on a
customer-by-customer
basis. New and existing customers are subject to a credit review
process, which evaluates the customers financial position
(for example, credit metrics, liquidity and credit rating) and
their ability to pay. If collectibility is not considered
probable at the outset of an arrangement in accordance with our
credit review process, revenue is not recognized until the cash
is collected.
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112
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We generally report revenues gross in the consolidated
statements of operations, as we typically act as the principal
in these transactions, take custody to the product, and incur
the risks and rewards of ownership. Effective April 1,
2006, any new or amended contracts for certain sales and
purchases of inventory with the same counterparty, when entered
into in contemplation of one another, are reported net as one
transaction. We recognize revenues for non-trading commodity
derivative activity net in the consolidated statements of
operations as gains and losses from commodity derivative
activity. These activities include mark-to-market gains and
losses on energy trading contracts and the settlement of
financial or physical energy trading contracts.
Quantities of natural gas or NGLs over-delivered or
under-delivered related to imbalance agreements with customers,
producers or pipelines are recorded monthly as other receivables
or other payables using current market prices or the
weighted-average prices of natural gas or NGLs at the plant or
system. These balances are settled with deliveries of natural
gas or NGLs, or with cash. Included in the consolidated balance
sheets as accounts receivable trade and accounts
receivable affiliates were imbalances of
$3.8 million and $1.6 million at December 31,
2008 and 2007, respectively. Included in the consolidated
balance sheets as accounts payable trade were
imbalances of $1.4 million and $1.1 million at
December 31, 2008 and 2007, respectively.
Significant Customer There were no
third party customers that accounted for more than 10% of total
operating revenues for the years ended December 31, 2008,
2007 and 2006. In addition, there were no third party customers
that accounted for more than 10% of total operating revenues for
the years ended December 31, 2008, 2007 and 2006 in any of
our business segments. We also had significant transactions with
affiliates, and with suppliers of natural gas and propane.
Environmental Expenditures
Environmental expenditures are expensed or
capitalized as appropriate, depending upon the future economic
benefit. Expenditures that relate to an existing condition
caused by past operations and that do not generate current or
future revenue are expensed. Liabilities for these expenditures
are recorded on an undiscounted basis when environmental
assessments
and/or
clean-ups
are probable and the costs can be reasonably estimated.
Environmental liabilities as of December 31, 2008 and 2007,
included in the consolidated balance sheets as other current
liabilities amounted to $1.3 million and $0.7 million,
respectively, and as other long-term liabilities amounted to
$0.6 million and $1.0 million, respectively.
Equity-Based Compensation Equity
classified stock-based compensation cost is measured at fair
value, based on the closing common unit price at grant date, and
is recognized as expense over the vesting period. Liability
classified stock-based compensation cost is remeasured at each
reporting date at fair value, based on the closing common unit
price, and is recognized as expense over the requisite service
period. Compensation expense for awards with graded vesting
provisions is recognized on a straight-line basis over the
requisite service period of each separately vesting portion of
the award. Awards granted to non-employees for acquiring, or in
conjunction with selling, goods and services, are measured at
the estimated fair value of the goods or services, or the fair
value of the award, whichever is more reliably measured.
Income Taxes We are structured as a
master limited partnership which is a pass-through entity for
federal income tax purposes. Our income tax expense includes
certain jurisdictions, including state, local, franchise and
margin taxes of the master limited partnership and subsidiaries.
We follow the asset and liability method of accounting for
income taxes. Under this method, deferred income taxes are
recognized for the tax consequences of temporary differences
between the financial statement carrying amounts and the tax
basis of the assets and liabilities. Our taxable income or loss,
which may vary substantially from the net income or loss
reported in the consolidated statements of operations, is
included in the federal returns of each partner.
Comprehensive Income or Loss
Comprehensive income or loss consists of net
income or loss and other comprehensive income or loss, which
includes unrealized gains and losses on the effective portion of
derivative instruments classified as cash flow hedges.
113
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net Income or Loss per Limited Partner Unit
Basic and diluted net income or loss per
limited partner unit is calculated by dividing limited
partners interest in net income or loss, less pro forma
general partner incentive distributions, by the weighted-average
number of outstanding limited partner units during the period.
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3.
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Recent
Accounting Pronouncements
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Statement of Financial Accounting Standards, or SFAS,
No. 162 The Hierarchy of Generally Accepted
Accounting Principles, or SFAS 162
In May 2008, the Financial Accounting Standards
Board, or FASB, issued SFAS 162, which is intended to
improve financial reporting by identifying a consistent
framework, or hierarchy, for selecting accounting principles to
be used in preparing financial statements that are presented in
conformity with GAAP for nongovernmental entities. SFAS 162
is effective 60 days following the Securities and Exchange
Commission, or SEC, approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The
Meaning of Present Fairly in Conformity with Generally Accepted
Accounting Principles. We have assessed the impact of the
adoption of SFAS 162, and believe that there will be no
impact on our consolidated results of operations, cash flows or
financial position.
FASB Staff Position, or FSP,
No. SFAS 142-3
Determination of the Useful Life of Intangible
Assets, or
FSP 142-3
In April 2008, the FASB issued
FSP 142-3,
which amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible.
FSP 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008, and interim periods
within those fiscal years. We are in the process of assessing
the impact of
FSP 142-3,
but do not expect a material impact on our consolidated results
of operations, cash flows and financial position as a result of
adoption.
SFAS No. 161 Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133, or SFAS 161
In March 2008, the FASB issued SFAS 161,
which requires disclosures of how and why an entity uses
derivative instruments, how derivative instruments and related
hedged items are accounted for and how derivative instruments
and related hedged items affect an entitys financial
position, financial performance, and cash flows. SFAS 161
is effective for us on January 1, 2009. We are in the
process of assessing the impact of SFAS 161 on our
disclosures, and will make the required disclosures in our
March 31, 2009 consolidated financial statements.
SFAS No. 160 Noncontrolling Interests in
Consolidated Financial Statements, an amendment of Accounting
Research Bulletin No. 51, or SFAS 160
In December 2007, the FASB issued SFAS 160,
which establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than
the parent, the amount of consolidated net income attributable
to the parent and to the noncontrolling interest, changes in a
parents ownership interest and the valuation of retained
noncontrolling equity investments when a subsidiary is
deconsolidated. SFAS 160 also establishes reporting
requirements that provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and
the interests of the noncontrolling owners. SFAS 160 was
effective for us on January 1, 2009, and did not have a
significant impact on our consolidated results of operations,
cash flows or financial position. As a result of adoption
effective January 1, 2009, we will reclassify
non-controlling interests in the consolidated balance sheets to
partners equity.
SFAS No. 141(R) Business Combinations
(revised 2007), or SFAS 141(R)
In December 2007, the FASB issued SFAS 141(R), which
requires the acquiring entity in a business combination to
recognize all (and only) the assets acquired and liabilities
assumed in the transaction; establishes the acquisition-date
fair value as the measurement objective for all assets acquired
and liabilities assumed; and requires the acquirer to disclose
to investors and other users all of the information they need to
evaluate and understand the nature and financial effect of the
business combination. SFAS 141(R) is effective for us on
January 1, 2009. As this standard will be applied
prospectively upon adoption, we will account for all
transactions with closing dates subsequent to the adoption date
in accordance with the provisions of the standard.
114
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities including
an amendment of FAS 115, or SFAS 159
In February 2007, the FASB issued SFAS 159,
which allows entities to choose, at specified election dates, to
measure eligible financial assets and liabilities at fair value
that are not otherwise required to be measured at fair value. If
a company elects the fair value option for an eligible item,
changes in that items fair value in subsequent reporting
periods must be recognized in current earnings. SFAS 159
also establishes presentation and disclosure requirements
designed to draw comparison between entities that elect
different measurement attributes for similar assets and
liabilities. The provisions of SFAS 159 became effective
for us on January 1, 2008. We have not elected the fair
value option relative to any of our financial assets and
liabilities which are not otherwise required to be measured at
fair value by other accounting standards. Therefore, there is no
effect of adoption reflected in our consolidated results of
operations, cash flows or financial position.
SFAS No. 157, Fair Value
Measurements, or SFAS 157 In
September 2006, the FASB issued SFAS 157, which was
effective for us on January 1, 2008. SFAS 157:
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defines fair value as the price that would be received to sell
an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date;
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establishes a framework for measuring fair value;
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establishes a three-level hierarchy for fair value measurements
based upon the transparency of inputs to the valuation of an
asset or liability as of the measurement date;
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nullifies the guidance in Emerging Issues Task Force, or EITF,
02-3,
Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Involved in Energy Trading and Risk
Management Activities, which required the deferral of profit
at inception of a transaction involving a derivative financial
instrument in the absence of observable data supporting the
valuation technique; and
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significantly expands the disclosure requirements around
instruments measured at fair value.
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Upon the adoption of this standard we incorporated the
marketplace participant view as prescribed by SFAS 157.
Such changes included, but were not limited to, changes in
valuation policies to reflect an exit price methodology, the
effect of considering our own non-performance risk on the
valuation of liabilities, and the effect of any change in our
credit rating or standing. As a result of adopting
SFAS 157, we recorded a transition adjustment of
approximately $5.8 million as an increase to earnings and
approximately $1.3 million as an increase to AOCI during
the three months ended March 31, 2008. All changes in our
valuation methodology have been incorporated into our fair value
calculations subsequent to adoption.
Pursuant to FASB Staff Position
157-2, the
FASB issued a partial deferral, ending on December 31,
2008, of the implementation of SFAS 157 as it relates to
all non-financial assets and liabilities where fair value is the
required measurement attribute by other accounting standards.
While we have adopted SFAS 157 for all financial assets and
liabilities effective January 1, 2008, we are in the
process of assessing the impact SFAS 157 will have on our
non-financial assets and liabilities, but do not expect a
material impact on our consolidated results of operations, cash
flows or financial position upon adoption.
FSP
No. 157-3
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active, or
FSP 157-3
In October 2008, the FASB issued
FSP 157-3,
which provides guidance in situations where a) observable
inputs do not exist, b) observable inputs exist but only in
an inactive market and c) how market quotes should be
considered when assessing the relevance of observable and
unobservable inputs to determine fair value.
FSP 157-3
was effective upon issuance, including prior periods for which
financial statements have not been issued. We believe that the
financial assets that are reflected in our financial statements
are transacted within active markets, and therefore, there is no
effect on our consolidated results of operations, cash flows or
financial positions as a result of the adoption of this FSP.
115
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
FSP of Financial Interpretation, or FIN,
39-1,
Amendment of FASB Interpretation No. 39, or
FSP
FIN 39-1
In April 2007, the FASB issued FSP
FIN 39-1,
which permits, but does not require, a reporting entity to
offset fair value amounts recognized for the right to reclaim
cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against the fair value amounts recognized
for derivative instruments executed with the same counterparty
under a master netting arrangement. FSP
FIN 39-1
became effective for us beginning on January 1, 2008;
however, we have elected to continue our policy of reflecting
our derivative asset and liability positions, as well as any
cash collateral, on a gross basis in our consolidated balance
sheets.
EITF 08-06
Equity Method Investment Accounting
Considerations, or
EITF 08-06
In November 2008, the EITF issued ETIF
08-06.
Although the issuance of FAS 141(R) and FAS 160 were
not intended to reconsider the accounting for equity method
investments, the application of the equity method is affected by
the issuance of these standards. This issue addresses
a) how the initial carrying value of an equity method
investment should be determined; b) how an impairment
assessment of an underlying indefinite-lived intangible asset of
an equity method investment should be performed; c) how an
equity method investees issuance of shares should be
accounted for and d) how to account for a change in an
investment from the equity method to the cost method. This issue
is effective for us on January 1, 2009, and although we do
not expect any changes to the manner in which we apply equity
method accounting, this guidance will be considered on a
prospective basis to transactions with equity method investees.
EITF 07-04
Application of the Two Class Method under
FASB Statement No. 128 to Master Limited Partnerships
or
EITF 07-04
In March 2008, the EITF issued ETIF
07-04. This
issue seeks to improve the comparability of earnings per unit,
or EPU, calculations for master limited partnerships with
incentive distribution rights in accordance with FASB Statement
No. 128 and its related interpretations. This issue is
effective for us on January 1, 2009 and will be
incorporated into our EPU calculations beginning with the
quarter ending March 31, 2009. We are in the process of
assessing the impact of
EITF 07-04
on our EPU calculations, and will make any required changes to
our calculation methodology for the quarter ending
March 31, 2009.
Gathering
and Compression Assets
On October 1, 2008, we acquired Michigan
Pipeline & Processing, LLC, or MPP, a privately held
company engaged in natural gas gathering and treating services
for natural gas produced from the Antrim Shale of northern
Michigan and natural gas transportation within Michigan. The
results of MPPs operations have been included in the
consolidated financial statements since that date. Under the
terms of the acquisition, we paid a purchase price of
$145.0 million, plus net working capital and other
adjustments of $3.4 million, subject to additional
customary purchase price adjustments. We may pay up to an
additional $15.0 million to the sellers depending on the
earnings of the assets after a three-year period. We financed
the acquisition through utilization of our credit facility. In
addition, we entered into a separate agreement that provides the
seller with available treating capacity on certain Michigan
assets. The seller agreed to pay up to $1.5 million
annually for up to nine years if they do not meet certain
criteria, including providing additional volumes for treatment.
These payments would reduce goodwill as a return of purchase
price. This agreement may be terminated earlier if certain
performance criteria of Michigan assets are satisfied. Certain
of these performance criteria were satisfied, and as a result,
the amount was reduced to approximately $0.8 million per
year as of December 31, 2008. We initially held a
$25.0 million letter of credit to secure the sellers
performance under this agreement and to secure the sellers
indemnification obligation under the acquisition agreement;
however as a result of the satisfaction of certain performance
conditions, this amount was reduced to approximately
$22.5 million as of December 31, 2008. The fees under
the Omnibus Agreement increased $0.4 million per year
effective October 1, 2008, in connection with the
acquisition.
116
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Under the purchase method of accounting, the assets and
liabilities of MPP were recorded at their respective fair values
as of the date of the acquisition, and we recorded goodwill of
approximately $6.7 million. The goodwill amount recognized
relates primarily to projected growth from new customers. The
values of certain assets and liabilities are preliminary, and
are subject to adjustment as additional information is obtained,
which when finalized may result in material adjustments. The
purchase price allocation is as follows:
|
|
|
|
|
|
|
(Millions)
|
|
|
Cash
|
|
$
|
1.7
|
|
Accounts receivable
|
|
|
2.1
|
|
Other assets
|
|
|
0.1
|
|
Other long term assets
|
|
|
3.8
|
|
Property, plant and equipment
|
|
|
116.1
|
|
Goodwill
|
|
|
6.7
|
|
Intangible assets
|
|
|
20.0
|
|
Other liabilities
|
|
|
(0.5
|
)
|
Non-controlling interest in joint venture
|
|
|
(1.6
|
)
|
|
|
|
|
|
Total purchase price allocation
|
|
$
|
148.4
|
|
|
|
|
|
|
In August 2007, we acquired certain subsidiaries of Momentum
Energy Group, Inc., or MEG, from DCP Midstream, LLC for
approximately $165.8 million. As a result of the
acquisition, we expanded our operations into the Piceance and
Powder River producing basins, thus diversifying our business
into new operating areas. The consideration consisted of
approximately $153.8 million of cash and the issuance of
275,735 common units to an affiliate of DCP Midstream, LLC that
were valued at approximately $12.0 million. We have
incurred post-closing purchase price adjustments totaling
$10.9 million for net working capital and general and
administrative charges. We financed this transaction with
$120.0 million of borrowings under our credit agreement,
along with the issuance of common units through a private
placement with certain institutional investors and cash on hand.
In August 2007, we issued 2,380,952 common limited partner units
in a private placement, pursuant to a common unit purchase
agreement with private owners of MEG or affiliates of such
owners, at $42.00 per unit, or approximately $100.0 million
in the aggregate. The proceeds from this private placement were
used to purchase high-grade securities to fully secure our term
loan borrowings. These units were registered with the SEC in
January 2008.
The transfer of the MEG subsidiaries between DCP Midstream, LLC
and us represents a transfer between entities under common
control. Transfers between entities under common control are
accounted for at DCP Midstream, LLCs carrying value,
similar to the pooling method. DCP Midstream, LLC recorded its
acquisition of the MEG subsidiaries under the purchase method of
accounting, whereby the assets and liabilities were recorded at
their respective fair values as of the date of the acquisition,
and we recorded goodwill of approximately $52.8 million,
including purchase price adjustments of $1.9 million during
the first quarter of
117
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008. The goodwill amount recognized relates primarily to
projected growth in the Piceance basin due to significant
natural gas reserves and high levels of drilling activity. The
purchase price allocation is as follows:
|
|
|
|
|
|
|
(Millions)
|
|
|
Cash consideration
|
|
$
|
153.8
|
|
Payable to DCP Midstream, LLC
|
|
|
10.9
|
|
Common limited partner units
|
|
|
12.0
|
|
|
|
|
|
|
Aggregate consideration
|
|
$
|
176.7
|
|
|
|
|
|
|
The purchase price allocation is as follows:
|
|
|
|
|
Cash
|
|
$
|
11.8
|
|
Accounts receivable
|
|
|
14.1
|
|
Other assets
|
|
|
1.5
|
|
Property, plant and equipment
|
|
|
127.8
|
|
Goodwill
|
|
|
52.8
|
|
Intangible assets
|
|
|
15.5
|
|
Accounts payable
|
|
|
(11.1
|
)
|
Other liabilities
|
|
|
(12.9
|
)
|
Non-controlling interest in joint venture
|
|
|
(22.8
|
)
|
|
|
|
|
|
Total purchase price allocation
|
|
$
|
176.7
|
|
|
|
|
|
|
On July 1, 2007, we acquired a 25% limited liability
company interest in East Texas, a 40% limited liability company
interest in Discovery and the Swap from DCP Midstream, LLC, for
aggregate consideration of approximately $271.3 million,
consisting of approximately $243.7 million in cash,
including net working capital of $1.3 million and other
adjustments, the issuance of 620,404 common units to DCP
Midstream, LLC valued at $27.0 million and the issuance of
12,661 general partner equivalent units valued at
$0.6 million. We financed the cash portion of this
transaction with borrowings of $245.9 million under our
credit facility. The $118.0 million excess purchase price
over the historical basis of the net acquired assets was
recorded as a reduction to partners equity, and the
$27.6 million of common and general partner equivalent
units issued as partial consideration for this transaction was
recorded as an increase to partners equity.
In May 2007, we acquired certain gathering and compression
assets located in southern Oklahoma, or the Southern Oklahoma
system, as well as related commodity purchase contracts, from
Anadarko Petroleum Corporation for approximately
$181.1 million.
In April 2007, we acquired certain gathering and compression
assets located in northern Louisiana from Laser Gathering
Company, LP for approximately $10.2 million.
The results of operations for MPP, MEG, and the Southern
Oklahoma and northern Louisiana acquired assets, have been
included prospectively, from the dates of acquisition, as part
of the Natural Gas Services segment.
Wholesale
Propane Logistics Business
On November 1, 2006, we acquired our wholesale propane
logistics business from DCP Midstream, LLC, in a transaction
among entities under common control, for aggregate consideration
of approximately $82.9 million, which consisted of
$77.3 million in cash ($9.9 million of which was paid
in January 2007), and the issuance of 200,312 Class C units
valued at approximately $5.6 million. Included in the
aggregate consideration was $10.5 million of costs incurred
through October 31, 2006, which were associated with the
construction of a new pipeline terminal. The $26.3 million
excess purchase price over the historical basis of
118
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the net acquired assets was recorded as a reduction to
partners equity, and the $5.6 million of common and
general partner equivalent units issued as partial consideration
for this transaction was recorded as an increase to
partners equity.
Combined
Financial Information
The following table presents pro forma information for the
consolidated statements of operations for the years ended 2008
and 2007, as if the acquisition of MPP had occurred at the
beginning of each year presented. There is no impact shown for
the MEG acquisition because there were no predecessor operations
of MEG at DCP Midstream, LLC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
DCP
|
|
|
|
|
|
|
|
|
DCP
|
|
|
|
DCP
|
|
|
|
|
|
Midstream
|
|
|
DCP
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Acquisition
|
|
|
Partners, LP
|
|
|
Midstream
|
|
|
Acquisition
|
|
|
Partners, LP
|
|
|
|
Partners, LP
|
|
|
of MPP
|
|
|
Pro Forma
|
|
|
Partners, LP
|
|
|
of MPP
|
|
|
Pro Forma
|
|
|
|
(Millions, except per unit amounts)
|
|
|
Total operating revenues
|
|
$
|
1,285.8
|
|
|
$
|
14.8
|
|
|
$
|
1,300.6
|
|
|
$
|
873.3
|
|
|
$
|
20.9
|
|
|
$
|
894.2
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
2.2
|
|
|
$
|
127.9
|
|
|
$
|
(15.8
|
)
|
|
$
|
1.2
|
|
|
$
|
(14.6
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to predecessor operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3.6
|
)
|
|
|
|
|
|
|
(3.6
|
)
|
General partner interest in net income
|
|
|
(11.9
|
)
|
|
|
|
|
|
|
(11.9
|
)
|
|
|
(2.2
|
)
|
|
|
(0.1
|
)
|
|
|
(2.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to limited partners
|
|
$
|
113.8
|
|
|
$
|
2.2
|
|
|
$
|
116.0
|
|
|
$
|
(21.6
|
)
|
|
$
|
1.1
|
|
|
$
|
(20.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit basic and
diluted
|
|
$
|
3.25
|
|
|
$
|
0.04
|
|
|
$
|
3.29
|
|
|
$
|
(1.05
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.00
|
)
|
The pro forma information is not intended to reflect actual
results that would have occurred if the companies had been
combined during the periods presented, nor is it intended to be
indicative of the results of operations that may be achieved by
us in the future.
|
|
5.
|
Agreements
and Transactions with Affiliates
|
DCP
Midstream, LLC
DCP Midstream, LLC provided centralized corporate functions on
behalf of our predecessor operations, including legal,
accounting, cash management, insurance administration and claims
processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll,
internal audit, taxes and engineering. The predecessors
share of those costs was allocated based on the
predecessors proportionate net investment (consisting of
property, plant and equipment, net, equity method investments,
and intangible assets, net) as compared to DCP Midstream,
LLCs net investment. In managements estimation, the
allocation methodologies used were reasonable and resulted in an
allocation to the predecessors of their respective costs of
doing business, which were borne by DCP Midstream, LLC.
Omnibus
Agreement
We have entered into an omnibus agreement, as amended, or the
Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus
Agreement, we are required to reimburse DCP Midstream, LLC for
salaries of operating personnel and employee benefits as well as
capital expenditures, maintenance and repair
119
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
costs, taxes and other direct costs incurred by DCP Midstream,
LLC on our behalf. We also pay DCP Midstream, LLC an annual fee
for centralized corporate functions performed by DCP Midstream,
LLC on our behalf, including legal, accounting, cash management,
insurance administration and claims processing, risk management,
health, safety and environmental, information technology, human
resources, credit, payroll, taxes and engineering. Under the
Omnibus Agreement, DCP Midstream, LLC provided parental
guarantees, totaling $43.0 million at December 31,
2008, to certain counterparties to our commodity derivative
instruments.
All of the fees under the Omnibus Agreement are subject to
adjustment annually for changes in the Consumer Price Index.
The Omnibus Agreement also addresses the following matters:
|
|
|
|
|
DCP Midstream, LLCs obligation to indemnify us for certain
liabilities and our obligation to indemnify DCP Midstream, LLC
for certain liabilities;
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support, including without limitation guarantees and
letters of credit, for our obligations related to derivative
financial instruments, such as commodity price hedging
contracts, to the extent that such credit support arrangements
were in effect as of the closing of our initial public offering
in December 2005, until the earlier to occur of the fifth
anniversary of the closing of our initial public offering or
such time as we obtain an investment grade credit rating from
either Moodys Investor Services, Inc. or
Standard & Poors Ratings Group with respect to
any of our unsecured indebtedness; and
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support, including without limitation guarantees and
letters of credit, for our obligations related to commercial
contracts with respect to its business or operations that were
in effect at the closing of our initial public offering until
the expiration of such contracts.
|
Any or all of the provisions of the Omnibus Agreement, other
than the indemnification provisions, will be terminable by DCP
Midstream, LLC at its option if the general partner is removed
without cause and units held by the general partner and its
affiliates are not voted in favor of that removal. The Omnibus
Agreement will also terminate in the event of a change of
control of us, the general partner (DCP Midstream GP, LP) or the
General Partner (DCP Midstream GP, LLC).
Following is a summary of the fees we incurred under the Omnibus
Agreement and the effective date for these fees, as well as
other fees paid to DCP Midstream, LLC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Terms
|
|
Effective Date
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(Millions)
|
|
|
Annual fee
|
|
2006
|
|
$
|
5.1
|
|
|
$
|
5.0
|
|
|
$
|
4.8
|
|
Wholesale propane logistics business
|
|
November 2006
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
0.3
|
|
Southern Oklahoma
|
|
May 2007
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
|
|
Discovery
|
|
July 2007
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
|
|
Additional services
|
|
August 2007
|
|
|
0.6
|
|
|
|
0.2
|
|
|
|
|
|
Momentum Energy Group, Inc.
|
|
August 2007
|
|
|
1.6
|
|
|
|
0.5
|
|
|
|
|
|
Michigan Pipeline & Processing, LLC
|
|
October 2008
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Omnibus Agreement
|
|
|
|
|
9.8
|
|
|
|
7.9
|
|
|
|
5.1
|
|
Other fees
|
|
|
|
|
1.8
|
|
|
|
2.1
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
11.6
|
|
|
$
|
10.0
|
|
|
$
|
8.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Competition
None of DCP Midstream, LLC, nor any of its affiliates, including
Spectra Energy and ConocoPhillips, is restricted, under either
the partnership agreement or the Omnibus Agreement, from
competing with us. DCP Midstream, LLC and any of its affiliates,
including Spectra Energy and ConocoPhillips, may acquire,
construct or dispose of additional midstream energy or other
assets in the future without any obligation to offer us the
opportunity to purchase or construct those assets.
Indemnification
The Black Lake pipeline has experienced increased operating
costs due to pipeline integrity testing that commenced in 2005
and was completed during the second quarter of 2008. Testing
revealed irregularities, the more severe of which were repaired
in October 2008 and the less severe of which are scheduled for
repair in 2009. DCP Midstream, LLC agreed to indemnify us for up
to $5.3 million of our pro rata share of any capital
contributions associated with repairing the Black Lake pipeline
that are determined to be necessary as a result of the pipeline
integrity testing. We anticipate repairs of approximately
$0.8 million on the pipeline, which will be funded directly
from Black Lake. We will not make contributions to Black Lake to
cover these expenses.
In connection with our acquisition of our wholesale propane
logistics business, DCP Midstream, LLC agreed to indemnify us
until October 31, 2009 for any claims for fines or
penalties of any governmental authority for periods prior to the
closing, agreed to indemnify us until October 31, 2010 if
certain contractual matters result in a claim, and agreed to
indemnify us indefinitely for breaches of the agreement. The
indemnity obligation for breach of the representations and
warranties is not effective until claims exceed in the aggregate
$680,000 and is subject to a maximum liability of
$6.8 million. This indemnity obligation for all other
claims other than a breach of the representations and warranties
does not become effective until an individual claim or series of
related claims exceed $50,000.
In connection with our acquisitions of East Texas and Discovery
from DCP Midstream, LLC, DCP Midstream, LLC agreed to indemnify
us until July 1, 2009 for any claims for fines or penalties
of any governmental authority for periods prior to the closing
and that are associated with certain East Texas assets that were
formerly owned by Gulf South and UP Fuels, and agreed to
indemnify us indefinitely for breaches of the agreement and
certain existing claims. The indemnity obligation for breach of
the representations and warranties is not effective until claims
exceed in the aggregate $2.7 million and is subject to a
maximum liability of $27.0 million. This indemnity
obligation for all other claims other than a breach of the
representations and warranties does not become effective until
an individual claim or series of related claims exceed $50,000.
In connection with our acquisition of certain subsidiaries of
MEG, DCP Midstream, LLC agreed to indemnify us until
August 29, 2008 for any breach of the representations and
warranties (except certain corporate related matters that
survive indefinitely), and indefinitely for breaches of the
agreement.
We have not pursued indemnification under these agreements.
Other
Agreements and Transactions with DCP Midstream,
LLC
DCP Midstream, LLC owns certain assets and is party to certain
contractual relationships around our Pelico system that are
periodically used for the benefit of Pelico. DCP Midstream, LLC
is able to source natural gas upstream of Pelico and deliver it
to the inlet of the Pelico system, and is able to take natural
gas from the outlet of the Pelico system and market it
downstream of Pelico. Because of DCP Midstream, LLCs
121
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
ability to move natural gas around Pelico, there are certain
contractual relationships around Pelico that define how natural
gas is bought and sold between us and DCP Midstream, LLC. The
agreement is described below:
|
|
|
|
|
DCP Midstream, LLC will supply Pelicos system requirements
that exceed its on-system supply. Accordingly, DCP Midstream,
LLC purchases natural gas and transports it to our Pelico
system, where we buy the gas from DCP Midstream, LLC at the
actual acquisition cost plus transportation service charges
incurred. We generally report purchases associated with these
activities gross in the consolidated statements of operations as
purchases of natural gas, propane and NGLs from affiliates.
|
|
|
|
If our Pelico system has volumes in excess of the on-system
demand, DCP Midstream, LLC will purchase the excess natural gas
from us and transport it to sales points at an index-based
price, less a contractually agreed-to marketing fee. We
generally report revenues associated with these activities gross
in the consolidated statements of operations as sales of natural
gas, propane and NGLs to affiliates.
|
|
|
|
In addition, DCP Midstream, LLC may purchase other excess
natural gas volumes at certain Pelico outlets for a price that
equals the original Pelico purchase price from DCP Midstream,
LLC, plus a portion of the index differential between upstream
sources to certain downstream indices with a maximum
differential and a minimum differential, plus a fixed fuel
charge and other related adjustments. We generally report
revenues and purchases associated with these activities net in
the consolidated statements of operations as transportation,
processing and other services to affiliates.
|
In addition, we sell NGLs processed at our Minden and Ada
plants, and sell condensate removed from the gas gathering
systems that deliver to the Minden and Ada plants, and from our
Pelico system to a subsidiary of DCP Midstream, LLC equal to
that subsidiarys net weighted-average sales price,
adjusted for transportation, processing and other charges from
the tailgate of the respective asset, which is recorded in the
consolidated statements of operations as sales of natural gas,
propane, NGLs and condensate to affiliates. We also sell propane
to a subsidiary of DCP Midstream, LLC.
We also have a contractual arrangement with a subsidiary of DCP
Midstream, LLC that provides that DCP Midstream, LLC will pay us
to transport NGLs over our Seabreeze pipeline, pursuant to a
fee-based rate that will be applied to the volumes transported.
DCP Midstream, LLC is the sole shipper on the Seabreeze pipeline
under a transportation agreement. We generally report revenues
associated with these activities in the consolidated statements
of operations as transportation, processing and other services
to affiliates.
In December 2006, we completed construction of our Wilbreeze
pipeline, which connects a DCP Midstream, LLC gas processing
plant to our Seabreeze pipeline. The project is supported by an
NGL product dedication agreement with DCP Midstream, LLC. We
generally report revenues, which are earned pursuant to a
fee-based rate applied to the volumes transported on this
pipeline, in the consolidated statements of operations as
transportation, processing and other services to affiliates.
We anticipate continuing to purchase commodities from and sell
commodities to DCP Midstream, LLC in the ordinary course of
business.
In conjunction with our acquisition of a 40% limited liability
company interest in Discovery from DCP Midstream, LLC in July
2007, we entered into a letter agreement with DCP Midstream, LLC
whereby DCP Midstream, LLC will make capital contributions to us
as reimbursement for certain Discovery capital projects, which
were forecasted to be completed prior to our acquisition of a
40% limited liability company interest in Discovery. Pursuant to
the letter agreement, DCP Midstream, LLC made capital
contributions to us of $3.8 million and $0.3 million
during 2008 and 2007, respectively to reimburse us for these
capital projects, which were substantially completed in 2008.
In the second quarter of 2006, we entered into a letter
agreement with DCP Midstream, LLC whereby DCP Midstream, LLC
will make capital contributions to us as reimbursement for
capital projects, which were
122
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
forecasted to be completed prior to our initial public offering,
but were not completed by that date. Pursuant to the letter
agreement, DCP Midstream, LLC made capital contributions to us
of $3.4 million during 2006 and $0.3 million during
2007, to reimburse us for the capital costs we incurred,
primarily for growth capital projects.
In July 2008, DCP Midstream, LLC issued additional parental
guarantees outside of the Omnibus Agreement, totaling
$200.0 million, to certain counterparties to our commodity
derivative instruments to mitigate a portion of our collateral
requirements with those counterparties. These guarantees were
reduced to $65.0 million as of December 31, 2008 to
correspond with lower commodity prices and collateral
requirements. We pay DCP Midstream, LLC interest of 0.5% per
annum on these outstanding guarantees.
DCP Midstream, LLC was a significant customer during the years
ended December 31, 2008, 2007 and 2006.
Duke
Energy
Prior to December 31, 2006, we purchased natural gas from
Duke Energy and its affiliates.
Spectra
Energy
We purchase a portion of our propane from and market propane on
behalf of Spectra Energy. We anticipate continuing to purchase
propane from and market propane on behalf of Spectra Energy in
the ordinary course of business.
During the second quarter of 2008, we entered into a propane
supply agreement with Spectra Energy. This agreement, effective
May 1, 2008 and terminating April 30, 2014, provides
us propane supply at our marine terminal, which is included in
our Wholesale Propane Logistics segment, for up to approximately
120 million gallons of propane annually. This contract
replaces the supply provided under a contract with a third party
that was terminated for non-performance during the first quarter
of 2008.
ConocoPhillips
We have multiple agreements whereby we provide a variety of
services to ConocoPhillips and its affiliates. The agreements
include fee-based and percent-of-proceeds gathering and
processing arrangements, gas purchase and gas sales agreements.
We anticipate continuing to purchase from and sell these
commodities to ConocoPhillips and its affiliates in the ordinary
course of business. In addition, we may be reimbursed by
ConocoPhillips for certain capital projects where the work is
performed by us. We received $1.9 million,
$2.9 million and $3.9 million of capital
reimbursements during the years ended December 31, 2008,
2007 and 2006, respectively.
123
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the transactions with affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
DCP Midstream, LLC:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, propane, NGLs and condensate
|
|
$
|
475.7
|
|
|
$
|
290.0
|
|
|
$
|
231.7
|
|
Transportation, processing and other
|
|
$
|
15.4
|
|
|
$
|
6.0
|
|
|
$
|
4.8
|
|
Purchases of natural gas, propane and NGLs
|
|
$
|
175.3
|
|
|
$
|
150.1
|
|
|
$
|
102.9
|
|
(Losses) gains from derivative activity, net
|
|
$
|
(3.1
|
)
|
|
$
|
(4.5
|
)
|
|
$
|
0.1
|
|
Operating and maintenance expense
|
|
$
|
|
|
|
$
|
0.4
|
|
|
$
|
0.2
|
|
General and administrative expense
|
|
$
|
11.6
|
|
|
$
|
10.0
|
|
|
$
|
8.1
|
|
Interest expense
|
|
$
|
0.4
|
|
|
$
|
|
|
|
$
|
|
|
Spectra Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, propane, NGLs and condensate
|
|
$
|
0.3
|
|
|
$
|
1.1
|
|
|
$
|
|
|
Transportation, processing and other
|
|
$
|
0.2
|
|
|
$
|
|
|
|
$
|
|
|
Purchases of natural gas, propane and NGLs
|
|
$
|
51.0
|
|
|
$
|
|
|
|
$
|
|
|
Duke Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas, propane and NGLs
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3.4
|
|
ConocoPhillips:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, propane, NGLs and condensate
|
|
$
|
1.8
|
|
|
$
|
6.6
|
|
|
$
|
1.1
|
|
Transportation, processing and other
|
|
$
|
10.4
|
|
|
$
|
10.6
|
|
|
$
|
8.0
|
|
Purchases of natural gas, propane and NGLs
|
|
$
|
36.6
|
|
|
$
|
29.2
|
|
|
$
|
12.9
|
|
We had accounts receivable and accounts payable with affiliates
as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
DCP Midstream, LLC:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
30.3
|
|
|
$
|
47.3
|
|
Accounts payable
|
|
$
|
27.9
|
|
|
$
|
53.3
|
|
Spectra Energy:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
4.0
|
|
|
$
|
1.5
|
|
Accounts payable
|
|
$
|
5.3
|
|
|
$
|
|
|
ConocoPhillips:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
2.5
|
|
|
$
|
3.3
|
|
Accounts payable
|
|
$
|
0.4
|
|
|
$
|
2.3
|
|
The following summarizes the unrealized losses on derivative
instruments with affiliates:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
DCP Midstream, LLC:
|
|
|
|
|
|
|
|
|
Unrealized losses current
|
|
$
|
(1.2
|
)
|
|
$
|
(2.7
|
)
|
124
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
6.
|
Property,
Plant and Equipment
|
A summary of property, plant and equipment by classification is
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable
|
|
|
December 31,
|
|
|
|
Life
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Millions)
|
|
|
Gathering systems
|
|
|
15 30 Years
|
|
|
$
|
405.0
|
|
|
$
|
371.3
|
|
Processing plants
|
|
|
25 30 Years
|
|
|
|
163.4
|
|
|
|
91.4
|
|
Terminals
|
|
|
25 30 Years
|
|
|
|
28.5
|
|
|
|
24.2
|
|
Transportation
|
|
|
25 30 Years
|
|
|
|
174.0
|
|
|
|
141.0
|
|
General plant
|
|
|
3 5 Years
|
|
|
|
6.0
|
|
|
|
4.0
|
|
Construction work in progress
|
|
|
|
|
|
|
43.5
|
|
|
|
25.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
|
|
|
|
820.4
|
|
|
|
657.4
|
|
Accumulated depreciation
|
|
|
|
|
|
|
(191.1
|
)
|
|
|
(156.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
|
|
|
$
|
629.3
|
|
|
$
|
500.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above amounts include accrued capital expenditures of
$12.3 million and $8.4 million as of December 31,
2008 and 2007, respectively, which are included in other current
liabilities in the consolidated balance sheets.
Depreciation expense was $34.4 million, $23.3 million
and $12.4 million for the years ended December 31,
2008, 2007 and 2006, respectively.
We lease one of our Michigan transmission pipelines to a third
party under a long-term contract. The carrying value of the
pipeline is approximately $23.0 million, with accumulated
depreciation of $0.2 million. Minimum future non-cancelable
rental payments are as follows:
|
|
|
|
|
Rental Payments
|
|
(Millions)
|
|
|
2009
|
|
$
|
3.0
|
|
2010
|
|
|
2.9
|
|
2011
|
|
|
2.9
|
|
2012
|
|
|
2.8
|
|
2013
|
|
|
2.3
|
|
Thereafter
|
|
|
20.7
|
|
|
|
|
|
|
Total
|
|
$
|
34.6
|
|
|
|
|
|
|
Asset Retirement Obligations Our asset
retirement obligations relate primarily to the retirement of
various gathering pipelines and processing facilities,
obligations related to right-of-way easement agreements, and
contractual leases for land use. We adjust our asset retirement
obligation each quarter for any liabilities incurred or settled
during the period, accretion expense and any revisions made to
the estimated cash flows. The asset retirement obligation,
included in other long-term liabilities in the consolidated
balance sheets, was $7.9 million and $3.1 million at
December 31, 2008 and 2007, respectively. The asset
retirement obligation increased in 2008 and 2007, respectively,
as a result of the MPP and MEG acquisitions. Accretion expense
for the years ended December 31, 2008 and 2007 was
$0.4 million and $0.1 million, respectively, and for
the year ended December 31, 2006 was not significant.
We identified various assets as having an indeterminate life,
for which there is no requirement to establish a fair value for
future retirement obligations associated with such assets. These
assets include certain pipelines,
125
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
gathering systems and processing facilities. A liability for
these asset retirement obligations will be recorded only if and
when a future retirement obligation with a determinable life is
identified. These assets have an indeterminate life because they
are owned and will operate for an indeterminate future period
when properly maintained. Additionally, if the portion of an
owned plant containing asbestos were to be modified or
dismantled, we would be legally required to remove the asbestos.
We currently have no plans to take actions that would require
the removal of the asbestos in these assets. Accordingly, the
fair value of the asset retirement obligation related to this
asbestos cannot be estimated and no obligation has been recorded.
|
|
7.
|
Goodwill
and Intangible Assets
|
The change in the carrying amount of goodwill is as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Beginning of period
|
|
$
|
80.2
|
|
|
$
|
29.3
|
|
Acquisitions
|
|
|
8.6
|
|
|
|
50.9
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
88.8
|
|
|
$
|
80.2
|
|
|
|
|
|
|
|
|
|
|
Goodwill increased during 2008 by $6.7 million as a result
of the MPP acquisition, and by $1.9 million for the final
purchase price allocation for the MEG subsidiaries acquired from
DCP Midstream, LLC. The increase in goodwill during 2007
represents the amount that we recognized in connection with our
acquisition of the MEG subsidiaries from DCP Midstream, LLC.
We perform an annual goodwill impairment test, and update the
test during interim periods if events or circumstances occur
that would more likely than not reduce the fair value of a
reporting unit below its carrying amount. We use a discounted
cash flow analysis supported by market valuation multiples to
perform the assessment. Key assumptions in the analysis include
the use of an appropriate discount rate, estimated future cash
flows and an estimated run rate of general and administrative
costs. In estimating cash flows, we incorporate current market
information, as well as historical and other factors, into our
forecasted commodity prices. Our annual goodwill impairment
tests indicated that our reporting units fair value
exceeded its carrying or book value.
During the fourth quarter of 2008, as a result of the decline in
the general equity market indices and in our unit price on the
New York Stock exchange, we updated our fair value analysis
using current marketplace assumptions and concluded that the
carrying value of goodwill is recoverable; therefore, we did not
record any impairment charges during the years ended
December 31, 2008, 2007 and 2006. However, given the
current volatility in the equity market, as well as volatile
commodity prices, we will continue to monitor the recoverability
of such amounts. Continued volatility and marketplace activity
may alter our conclusion in the future, and could result in the
recognition of an impairment charge.
Intangible assets consist of customer contracts, including
commodity purchase, transportation and processing contracts, and
related relationships. The gross carrying amount and accumulated
amortization of these intangible assets are included in the
accompanying consolidated balance sheets as intangible assets,
net, and are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Gross carrying amount
|
|
$
|
52.5
|
|
|
$
|
32.4
|
|
Accumulated amortization
|
|
|
(4.8
|
)
|
|
|
(2.7
|
)
|
|
|
|
|
|
|
|
|
|
Intangible assets, net
|
|
$
|
47.7
|
|
|
$
|
29.7
|
|
|
|
|
|
|
|
|
|
|
126
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Intangible assets increased in 2008 as a result of the MPP
acquisition.
For the years ended December 31, 2008, 2007 and 2006, we
recorded amortization expense of $2.1 million,
$1.1 million and $0.4 million, respectively. As of
December 31, 2008, the remaining amortization periods range
from approximately less than one year to 25 years, with a
weighted-average remaining period of approximately 21 years.
Estimated future amortization for these intangible assets is as
follows:
|
|
|
|
|
|
|
Estimated Future
|
|
|
|
Amortization
|
|
|
|
(Millions)
|
|
|
2009
|
|
$
|
2.6
|
|
2010
|
|
|
2.6
|
|
2011
|
|
|
2.3
|
|
2012
|
|
|
2.3
|
|
2013
|
|
|
2.3
|
|
Thereafter
|
|
|
35.6
|
|
|
|
|
|
|
Total
|
|
$
|
47.7
|
|
|
|
|
|
|
|
|
8.
|
Equity
Method Investments
|
The following table summarizes our equity method investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
|
|
|
|
|
|
Ownership as of
|
|
|
Carrying Value as of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008 and 2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Millions)
|
|
|
Discovery Producer Services LLC
|
|
|
40
|
%
|
|
$
|
105.0
|
|
|
$
|
117.9
|
|
DCP East Texas Holdings, LLC
|
|
|
25
|
%
|
|
|
63.9
|
|
|
|
62.9
|
|
Black Lake Pipe Line Company
|
|
|
45
|
%
|
|
|
6.3
|
|
|
|
6.2
|
|
Other
|
|
|
50
|
%
|
|
|
0.2
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity method investments
|
|
|
|
|
|
$
|
175.4
|
|
|
$
|
187.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery operates a
600 MMcf/d
cryogenic natural gas processing plant near Larose, Louisiana, a
natural gas liquids fractionator plant near Paradis, Louisiana,
a natural gas pipeline from offshore deep water in the Gulf of
Mexico that transports gas to its processing plant in Larose,
Louisiana with a design capacity of
600 MMcf/d
and approximately 280 miles of pipe, and several laterals
in the Gulf of Mexico. There was a deficit between the carrying
amount of the investment and the underlying equity of Discovery
of $39.7 million and $43.7 million at
December 31, 2008 and 2007, respectively, which is
associated with, and is being accreted over, the life of the
underlying long-lived assets of Discovery.
East Texas is engaged in the business of gathering,
transporting, treating, compressing, processing, and
fractionating natural gas and NGLs. Its operations, located near
Carthage, Texas, include a natural gas processing complex with a
total capacity of
780 MMcf/d
and a natural gas liquids fractionator. The facility is
connected to an approximately
900-mile
gathering system, as well as third party gathering systems. The
complex includes and is adjacent to the Carthage Hub, which
delivers residue gas to interstate and intrastate pipelines. The
Carthage Hub, with an aggregate delivery capacity of
1.5 Bcf/d, acts as a key exchange point for the purchase
and sale of residue gas.
127
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Black Lake owns a
317-mile NGL
pipeline, with a throughput capacity of approximately
40 MBbls/d. The pipeline receives NGLs from a number of gas
plants in Louisiana and Texas. There was a deficit between the
carrying amount of the investment and the underlying equity of
Black Lake of $6.0 million and $6.4 million at
December 31, 2008 and 2007, respectively, which is
associated with, and is being accreted over, the life of the
underlying long-lived assets of Black Lake.
Earnings from equity method investments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Discovery Producer Services LLC
|
|
$
|
17.4
|
|
|
$
|
24.1
|
|
|
$
|
16.9
|
|
DCP East Texas Holdings, LLC
|
|
|
16.1
|
|
|
|
14.6
|
|
|
|
12.0
|
|
Black Lake Pipe Line Company and other
|
|
|
0.8
|
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total earnings from equity method investments
|
|
$
|
34.3
|
|
|
$
|
39.3
|
|
|
$
|
29.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions from equity method investments
|
|
$
|
59.9
|
|
|
$
|
38.9
|
|
|
$
|
25.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity method investments, net of distributions
|
|
$
|
(25.6
|
)
|
|
$
|
0.4
|
|
|
$
|
3.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following summarizes financial information of our equity
method investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
792.7
|
|
|
$
|
739.6
|
|
|
$
|
686.9
|
|
Operating expenses
|
|
$
|
(696.9
|
)
|
|
$
|
634.6
|
|
|
$
|
612.2
|
|
Net income
|
|
$
|
99.8
|
|
|
$
|
106.8
|
|
|
$
|
77.4
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Balance sheet:
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
104.3
|
|
|
$
|
168.8
|
|
Long-term assets
|
|
|
646.3
|
|
|
|
630.3
|
|
Current liabilities
|
|
|
(84.4
|
)
|
|
|
(100.9
|
)
|
Long-term liabilities
|
|
|
(22.4
|
)
|
|
|
(14.9
|
)
|
|
|
|
|
|
|
|
|
|
Net assets
|
|
$
|
643.8
|
|
|
$
|
683.3
|
|
|
|
|
|
|
|
|
|
|
|
|
9.
|
Fair
Value Measurement
|
Determination
of Fair Value
Below is a general description of our valuation methodologies
for derivative financial assets and liabilities, as well as
short-term and restricted investments, which are measured at
fair value. Fair values are generally based upon quoted market
prices, where available. In the event that listed market prices
or quotes are not available, we determine fair value based upon
a market quote, adjusted by other market-based or independently
sourced market data such as historical commodity volatilities,
crude oil future yield curves,
and/or
counterparty specific considerations. These adjustments result
in a fair value for each asset or liability under an exit
price methodology, in line with how we believe a
marketplace participant would value that
128
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
asset or liability. These adjustments may include amounts to
reflect counterparty credit quality, the effect of our own
creditworthiness, the time value of money
and/or the
liquidity of the market.
|
|
|
|
|
Counterparty credit valuation adjustments are necessary when the
market price of an instrument is not indicative of the fair
value as a result of the credit quality of the counterparty.
Generally, market quotes assume that all counterparties have
near zero, or low, default rates and have equal credit quality.
Therefore, an adjustment may be necessary to reflect the credit
quality of a specific counterparty to determine the fair value
of the instrument. We record counterparty credit valuation
adjustments on all derivatives that are in a net asset position
as of the measurement date in accordance with our established
counterparty credit policy, which takes into account any
collateral margin that a counterparty may have posted with us.
|
|
|
|
Entity valuation adjustments are necessary to reflect the effect
of our own credit quality on the fair value of our net liability
position with each counterparty. This adjustment takes into
account any credit enhancements, such as collateral margin we
may have posted with a counterparty, as well as any letters of
credit that we have provided. The methodology to determine this
adjustment is consistent with how we evaluate counterparty
credit risk, taking into account our own credit rating, current
credit spreads, as well as any change in such spreads since the
last measurement date.
|
|
|
|
Liquidity valuation adjustments are necessary when we are not
able to observe a recent market price for financial instruments
that trade in less active markets for the fair value to reflect
the cost of exiting the position. Exchange traded contracts are
valued at market value without making any additional valuation
adjustments and, therefore, no liquidity reserve is applied. For
contracts other than exchange traded instruments, we mark our
positions to the midpoint of the bid/ask spread, and record a
liquidity reserve based upon our total net position. We believe
that such practice results in the most reliable fair value
measurement as viewed by a market participant.
|
We manage our derivative instruments on a portfolio basis and
the valuation adjustments described above are calculated on this
basis. We believe that the portfolio level approach represents
the highest and best use for these assets as there are benefits
inherent in naturally offsetting positions within the portfolio
at any given time, and this approach is consistent with how a
market participant would view and value the assets. Although we
take a portfolio approach to managing these assets/liabilities,
in order to reflect the fair value of any one individual
contract within the portfolio, we allocate all valuation
adjustments down to the contract level, to the extent deemed
necessary, based upon either the notional contract volume, or
the contract value, whichever is more applicable.
The methods described above may produce a fair value calculation
that may not be indicative of net realizable value or reflective
of future fair values. While we believe that our valuation
methods are appropriate and consistent with other marketplace
participants, we recognize that the use of different
methodologies or assumptions to determine the fair value of
certain financial instruments could result in a different
estimate of fair value at the reporting date. We review our fair
value policies on a regular basis taking into consideration
changes in the marketplace and, if necessary, will adjust our
policies accordingly. See Note 13 Risk Management
Activities Credit Risk and Financial Instruments.
Valuation
Hierarchy
Our fair value measurements are grouped into a three-level
valuation hierarchy. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability
as of the measurement date. The three levels are defined as
follows.
|
|
|
|
|
Level 1 inputs are unadjusted quoted prices for
identical assets or liabilities in active markets.
|
129
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
Level 2 inputs include quoted prices for
similar assets and liabilities in active markets, and
inputs that are observable for the asset or liability, either
directly or indirectly, for substantially the full term of the
financial instrument.
|
|
|
|
Level 3 inputs are unobservable and considered
significant to the fair value measurement.
|
A financial instruments categorization within the
hierarchy is based upon the lowest level of input that is
significant to the fair value measurement. Following is a
description of the valuation methodologies used as well as the
general classification of such instruments pursuant to the
hierarchy.
Commodity
Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments,
which may include over the counter, or OTC, instruments, such as
natural gas, crude oil or NGL contracts.
Within our Natural Gas Services segment we typically use OTC
derivative contracts in order to mitigate a portion of our
exposure to natural gas, NGL and condensate price changes. These
instruments are generally classified as Level 2. Depending
upon market conditions and our strategy, we may enter into OTC
derivative positions with a significant time horizon to
maturity, and market prices for these OTC derivatives may only
be readily observable for a portion of the duration of the
instrument. In order to calculate the fair value of these
instruments, readily observable market information is utilized
to the extent that it is available; however, in the event that
readily observable market data is not available, we may
interpolate or extrapolate based upon observable data. In
instances where we utilize an interpolated or extrapolated
value, and it is considered significant to the valuation of the
contract as a whole, we would classify the instrument within
Level 3.
Within our Wholesale Propane Logistics segment, we may enter
into a variety of financial instruments to either secure sales
or purchase prices, or capture a variety of market
opportunities. Since financial instruments for NGLs tend to be
counterparty and location specific, we primarily use the OTC
derivative instrument markets, which are not as active and
liquid as exchange traded instruments. Market quotes for such
contracts may only be available for short dated positions (up to
six months), and a market itself may not exist beyond such time
horizon. Contracts entered into with a relatively short time
horizon for which prices are readily observable in the OTC
market are generally classified within Level 2. Contracts
with a longer time horizon, for which we internally generate a
forward curve to value such instruments, are generally
classified within Level 3. The internally generated curve
may utilize a variety of assumptions including, but not limited
to, historical and future expected correlation of NGL prices to
crude oil prices, the knowledge of expected supply sources
coming on line, expected weather trends within certain regions
of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at
the end of each financial quarter depending upon the extent to
which the valuation inputs are observable. Generally, an
instrument will move toward a level within the hierarchy that
requires a lower degree of judgment as the time to maturity
approaches, and as the markets in which the asset trades will
likely become more liquid and prices more readily available in
the market, thus reducing the need to rely upon our internally
developed assumptions. However, the level of a given instrument
may change, in either direction, depending upon market
conditions and the availability of market observable data.
Interest
Rate Derivative Assets and Liabilities
We have interest rate swap agreements as part of our overall
capital strategy. These instruments effectively exchange a
portion of our floating rate debt for fixed rate debt, and are
held with major financial institutions, which are expected to
fully perform under the terms of our agreements. The swaps are
generally priced based upon a United States Treasury instrument
with similar duration, adjusted by the credit spread between our
company and the United States Treasury instrument. Given that a
significant portion of the swap
130
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
value is derived from the credit spread, which may be observed
by comparing similar assets in the market, these instruments are
classified within Level 2. Default risk on either side of
the swap transaction is also considered in the valuation. We
record counterparty credit, our entity valuation, as well as
liquidity reserves in the valuation of our interest rate swaps;
however, these reserves are not considered to be a significant
input to the overall valuation.
Short-Term
and Restricted Investments
We are required to post collateral to secure the term loan
portion of our credit facility, and may elect to invest a
portion of our available cash balances in various financial
instruments such as commercial paper, money market instruments
and highly rated tax-exempt debt securities that have stated
maturities of 20 years or more, which are categorized as
available-for-sale securities. The money market instruments are
generally priced at acquisition cost, plus accreted interest at
the stated rate, which approximates fair value, without any
additional adjustments. Given that there is no observable
exchange traded market for identical money market securities, we
have classified these instruments within Level 2.
Investments in commercial paper and highly rated tax-exempt debt
securities are priced using a yield curve for similarly rated
instruments, and are classified within Level 2. As of
December 31, 2008, nearly all of our short-term and
restricted investments were held in the form of money market
securities. By virtue of our balances in these funds on
September 19, 2008, all of these investments are eligible
for, and the funds are participating in, the U.S. Treasury
Departments Temporary Guarantee Program for Money Market
Funds.
The following table presents the financial instruments carried
at fair value as of December 31, 2008, by consolidated
balance sheet caption and by valuation hierarchy, as described
above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal Models
|
|
|
Internal Models
|
|
|
|
|
|
|
Quoted Market
|
|
|
with Significant
|
|
|
with Significant
|
|
|
|
|
|
|
Prices in
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
|
Active Markets
|
|
|
Market Inputs
|
|
|
Market Inputs
|
|
|
Total Carrying
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
|
(Millions)
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments(a)
|
|
$
|
|
|
|
$
|
15.1
|
|
|
$
|
0.3
|
|
|
$
|
15.4
|
|
Long-term assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted investments
|
|
$
|
|
|
|
$
|
60.2
|
|
|
$
|
|
|
|
$
|
60.2
|
|
Commodity derivative instruments(b)
|
|
$
|
|
|
|
$
|
6.9
|
|
|
$
|
1.7
|
|
|
$
|
8.6
|
|
Interest rate instruments(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Current liabilities(c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
|
|
|
$
|
(1.2
|
)
|
|
$
|
|
|
|
$
|
(1.2
|
)
|
Interest rate instruments
|
|
$
|
|
|
|
$
|
(16.5
|
)
|
|
$
|
|
|
|
$
|
(16.5
|
)
|
Long-term liabilities(d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
|
|
|
$
|
(3.2
|
)
|
|
$
|
|
|
|
$
|
(3.2
|
)
|
Interest rate instruments
|
|
$
|
|
|
|
$
|
(22.8
|
)
|
|
$
|
|
|
|
$
|
(22.8
|
)
|
|
|
|
(a) |
|
Included in current unrealized gains on derivative instruments
in our consolidated balance sheets. |
|
(b) |
|
Included in long-term unrealized gains on derivative instruments
in our consolidated balance sheets. |
|
(c) |
|
Included in current unrealized losses on derivative instruments
in our consolidated balance sheets. |
|
(d) |
|
Included in long-term unrealized losses on derivative
instruments in our consolidated balance sheets. |
131
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Changes
in Level 3 Fair Value Measurements
The table below illustrates a rollforward of the amounts
included in our consolidated balance sheets for derivative
financial instruments that we have classified within
Level 3. The determination to classify a financial
instrument within Level 3 is based upon the significance of
the unobservable factors used in determining the overall fair
value of the instrument. Since financial instruments classified
as Level 3 typically include a combination of observable
components (that is, components that are actively quoted and can
be validated to external sources) and unobservable components,
the gains and losses in the table below may include changes in
fair value due in part to observable market factors, or changes
to our assumptions on the unobservable components. Depending
upon the information readily observable in the market,
and/or the
use of unobservable inputs, which are significant to the overall
valuation, the classification of any individual financial
instrument may differ from one measurement date to the next. In
the event that there is a movement to/from the classification of
an instrument as Level 3, we have reflected such items in
the table below within the Transfers In/Out of
Level 3 caption.
We manage our overall risk at the portfolio level, and in the
execution of our strategy, we may use a combination of financial
instruments, which may be classified within any level. Since
Level 1 and Level 2 risk management instruments are
not included in the rollforward below, the gains or losses in
the table do not reflect the effect of our total risk management
activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Realized
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and Unrealized
|
|
|
|
|
|
|
|
|
|
|
|
Net Unrealized
|
|
|
|
Balance at
|
|
|
Gains Included
|
|
|
Transfers In/
|
|
|
Purchases,
|
|
|
Balance at
|
|
|
Gains (Losses)
|
|
|
|
December 31,
|
|
|
in (Losses)
|
|
|
Out of
|
|
|
Issuances and
|
|
|
December 31,
|
|
|
Still Held Included
|
|
|
|
2007
|
|
|
Earnings
|
|
|
Level 3(a)
|
|
|
Settlements, Net
|
|
|
2008
|
|
|
in Earnings(b)
|
|
|
|
(Millions)
|
|
|
Commodity derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
0.2
|
|
|
$
|
0.8
|
|
|
$
|
|
|
|
$
|
(0.7
|
)
|
|
$
|
0.3
|
|
|
$
|
0.3
|
|
Long-term assets
|
|
$
|
1.5
|
|
|
$
|
1.0
|
|
|
$
|
(0.8
|
)
|
|
$
|
|
|
|
$
|
1.7
|
|
|
$
|
1.0
|
|
Current liabilities
|
|
$
|
(1.6
|
)
|
|
$
|
(0.2
|
)
|
|
$
|
|
|
|
$
|
1.8
|
|
|
$
|
|
|
|
$
|
|
|
Long-term liabilities
|
|
$
|
(0.2
|
)
|
|
$
|
0.2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.2
|
|
|
|
|
(a) |
|
Amounts transferred in are reflected at fair value as of the end
of the period and amounts transferred out are reflected at fair
value at the beginning of the period. |
|
(b) |
|
Represents the amount of total gains or losses for the period,
included in gains or losses from commodity derivative activity,
net, attributable to change in unrealized gains (losses)
relating to assets and liabilities classified as Level 3
that are still held at December 31, 2008. |
|
|
10.
|
Estimated
Fair Value of Financial Instruments
|
We have determined fair value amounts using available market
information and appropriate valuation methodologies. However,
considerable judgment is required in interpreting market data to
develop the estimates of fair value. Accordingly, the estimates
presented herein are not necessarily indicative of the amounts
that we could realize in a current market exchange. The use of
different market assumptions
and/or
estimation methods may have a material effect on the estimated
fair value amounts.
The fair value of restricted investments, accounts receivable
and accounts payable are not materially different from their
carrying amounts because of the short term nature of these
instruments or the stated rates approximating market rates.
Unrealized gains and unrealized losses on derivative instruments
are carried at fair value. The carrying value of long-term debt
approximates fair value, as the interest rate is variable and
reflects current market conditions.
132
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-term debt was as follows:
|
|
|
|
|
|
|
|
|
|
|
Principal Amount
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Revolving credit facility, weighed-average interest rate of
2.08% and 5.47%, respectively, due June 21, 2012(a)
|
|
$
|
596.5
|
|
|
$
|
530.0
|
|
Term loan facility, interest rate 1.54% and 5.05%, respectively,
due June 21, 2012(b)
|
|
|
60.0
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
656.5
|
|
|
$
|
630.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
$575.0 million of debt has been swapped to a fixed rate
obligation with effective fixed rates ranging from 2.26% to
5.19%, for a net effective rate of 4.48% on the
$596.5 million of outstanding debt under our revolving
credit facility as of December 31, 2008. |
|
(b) |
|
The term loan facility is fully secured by restricted
investments. |
Credit
Agreement
We have an $824.6 million
5-year
credit agreement that matures June 21, 2012, or the Credit
Agreement, which consists of:
|
|
|
|
|
a $764.6 million revolving credit facility; and
|
|
|
|
a $60.0 million term loan facility.
|
At December 31, 2008 and 2007, we had $0.3 million and
$0.2 million of letters of credit issued under the credit
agreement outstanding, respectively. Outstanding balances under
the term loan facility are fully collateralized by investments
in high-grade securities, which are classified as restricted
investments in the accompanying consolidated balance sheet as of
December 31, 2008 and 2007. As of December 31, 2008,
the available capacity under the revolving credit facility was
$171.5 million, which is net of approximately
$21.7 million non-participation by Lehman Brothers
Commercial Bank, or Lehman Brothers, as discussed below. We
incurred $0.6 million of debt issuance costs during 2007
associated with the Credit Agreement. These expenses are
deferred as other long-term assets in the consolidated balance
sheet and will be amortized over the term of the Credit
Agreement.
Under the Credit Agreement, indebtedness under the revolving
credit facility bears interest at either: (1) the higher of
Wachovia Banks prime rate or the Federal Funds rate plus
0.50%; or (2) LIBOR plus an applicable margin, which ranges
from 0.23% to 0.575% dependent upon our leverage level or credit
rating. The revolving credit facility incurs an annual facility
fee of 0.07% to 0.175% depending on our applicable leverage
level or debt rating. This fee is paid on drawn and undrawn
portions of the revolving credit facility. The term loan
facility bears interest at a rate equal to either:
(1) LIBOR plus 0.10%; or (2) the higher of Wachovia
Banks prime rate or the Federal Funds rate plus 0.50%.
The Credit Agreement requires us to maintain a leverage ratio
(the ratio of our consolidated indebtedness to our consolidated
EBITDA, in each case as is defined by the Credit Agreement) of
not more than 5.0 to 1.0, and on a temporary basis for not more
than three consecutive quarters (including the quarter in which
such acquisition is consummated) following the consummation of
asset acquisitions in the midstream energy business of not more
than 5.5 to 1.0. The Credit Agreement also requires us to
maintain an interest coverage ratio (the ratio of our
consolidated EBITDA to our consolidated interest expense, in
each case as is defined by the Credit Agreement) of equal or
greater than 2.5 to 1.0 determined as of the last day of each
quarter for the four-quarter period ending on the date of
determination.
133
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Lehman Brothers is a lender in our Credit Agreement. Lehman
Brothers has not funded its portion of our borrowing requests
since its bankruptcy, and it is uncertain whether it will
participate in future borrowing requests. Accordingly, the
availability of new borrowings under the Credit Agreement has
been reduced by approximately $25.4 million as of
December 31, 2008. Our borrowing capacity may be further
limited by the Credit Agreements financial covenant
requirements. Except in the case of a default, amounts borrowed
under our credit facility will not mature prior to the
June 21, 2012 maturity date.
Bridge
Loan
In May 2007, we entered into a two-month bridge loan, or the
Bridge Loan, which provided for borrowings up to
$100.0 million, and had terms and conditions substantially
similar to those of our Credit Agreement. In conjunction with
our entering into the Bridge Loan, our Credit Agreement was
amended to provide for additional unsecured indebtedness, of an
amount not to exceed $100.0 million, which was due and
payable no later than August 9, 2007.
We used borrowings on the Bridge Loan of $88.0 million to
partially fund the Southern Oklahoma acquisition. The remaining
$12.0 million available for borrowing on the Bridge Loan
was not utilized. We used a portion of the net proceeds of a
private placement of limited partner units to extinguish the
$88.0 million outstanding on the Bridge Loan in June 2007.
Other
Agreements
As of December 31, 2008, we had an outstanding letter of
credit with a counterparty to our commodity derivative
instruments of $10.0 million, which reduces the amount of
cash we may be required to post as collateral. This letter of
credit was issued directly by a financial institution and does
not reduce the available capacity under our credit facility.
|
|
12.
|
Partnership
Equity and Distributions
|
General Our partnership agreement
requires that, within 45 days after the end of each
quarter, we distribute all of our Available Cash (defined below)
to unitholders of record on the applicable record date, as
determined by our general partner.
In November 2007, our universal shelf registration statement on
Form S-3
was declared effective by the SEC. The universal shelf
registration statement has a maximum aggregate offering price of
$1.5 billion, which will allow us to register and issue
additional partnership units and debt obligations.
In June 2007, we entered into a private placement agreement with
a group of institutional investors for $130.0 million,
representing 3,005,780 common limited partner units at a price
of $43.25 per unit, and received proceeds of
$128.5 million, net of offering costs.
In July 2007, we issued 620,404 common units to DCP Midstream,
LLC as partial consideration for the purchase of Discovery, East
Texas and the Swap. In August 2007, we issued 275,735 common
units to DCP Midstream, LLC as partial consideration for the
purchase of certain subsidiaries of MEG.
In August 2007, we issued 2,380,952 common units in a private
placement, pursuant to a common unit purchase agreement with
private owners of MEG or affiliates of such owners, at $42.00
per unit, or approximately $100.0 million in the aggregate.
In January 2008, our registration statement on
Form S-3
to register the 3,005,780 common limited partner units
represented in the June 2007 private placement agreement and the
2,380,952 common limited partner units represented in the August
2007 private placement agreement was declared effective by the
SEC.
134
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In March 2008, we issued 4,250,000 common limited partner units
at $32.44 per unit, and received proceeds of
$132.1 million, net of offering costs.
Definition of Available Cash Available
Cash, for any quarter, consists of all cash and cash equivalents
on hand at the end of that quarter:
|
|
|
|
|
less the amount of cash reserves established by the general
partner to:
|
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to the unitholders and to our
general partner for any one or more of the next four quarters;
|
|
|
|
|
|
plus, if our general partner so determines, all or a portion of
cash and cash equivalents on hand on the date of determination
of Available Cash for the quarter.
|
General Partner Interest and Incentive Distribution Rights
Prior to June 2007, the general
partner was entitled to 2% of all quarterly distributions that
we make prior to our liquidation. The general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its current general partner
interest. The general partner has not participated in certain
issuances of common units. Therefore, the general partners
2% interest has been diluted to approximately 1% as of
December 31, 2008.
The incentive distribution rights held by the general partner
entitle it to receive an increasing share of Available Cash when
pre-defined distribution targets are achieved. Currently, our
distribution to our general partner related to its incentive
distribution rights is at the highest level. The general
partners incentive distribution rights were not reduced as
a result of these private placement agreements, and will not be
reduced if we issue additional units in the future and the
general partner does not contribute a proportionate amount of
capital to us to maintain its current general partner interest.
Please read the Distributions of Available Cash during the
Subordination Period and Distributions of Available Cash
after the Subordination Period sections below for more
details about the distribution targets and their impact on the
general partners incentive distribution rights.
Class C Units On July 2,
2007, the Class C units were converted to common units.
Subordinated Units All of the
subordinated units are held by DCP Midstream, LLC. Our
partnership agreement provides that, during the subordination
period, the common units will have the right to receive
distributions of Available Cash each quarter in an amount equal
to $0.35 per common unit, or the Minimum Quarterly Distribution,
plus any arrearages in the payment of the Minimum Quarterly
Distribution on the common units from prior quarters, before any
distributions of Available Cash may be made on the subordinated
units. These units are deemed subordinated because
for a period of time, referred to as the subordination period,
the subordinated units will not be entitled to receive any
distributions until the common units have received the Minimum
Quarterly Distribution plus any arrearages from prior quarters.
Furthermore, no arrearages will be paid on the subordinated
units. The practical effect of the subordinated units is to
increase the likelihood that during the subordination period
there will be Available Cash to be distributed on the common
units. The subordination period will end, and the subordinated
units will convert to common units, on a one for one basis, when
certain distribution requirements, as defined in the partnership
agreement, have been met. The subordination period has an early
termination provision that permits 50% of the subordinated units
to convert to common units on the second business day following
the first quarter distribution in 2008 and the other 50% of the
subordinated units to convert to common units on the second
business day following the first quarter distribution in 2009,
provided the tests for ending the subordination period contained
in the partnership agreement are satisfied. In 2008, we
determined that the criteria set forth in the partnership
agreement for early termination of the subordination period
occurred in February 2008 and,
135
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
therefore, 50% of the subordinated units, or
3,571,428 units, converted into common units. We determined
that the criteria set forth in the partnership agreement for
early termination of the subordination period occurred in
February 2009 and, therefore, the remaining
3,571,429 units, converted into common units. Our board of
directors and the conflicts committee of the board certified
that all conditions for early conversion were satisfied. The
rights of the subordinated unitholders, other than the
distribution rights described above, are substantially the same
as the rights of the common unitholders.
Distributions of Available Cash during the Subordination
Period Our partnership agreement, after
adjustment for the general partners relative ownership
level, currently approximately 1%, requires that we make
distributions of Available Cash for any quarter during the
subordination period in the following manner:
|
|
|
|
|
first, to the common unitholders and the general partner,
in accordance with their pro rata interest, until we distribute
for each outstanding common unit an amount equal to the Minimum
Quarterly Distribution for that quarter;
|
|
|
|
second, to the common unitholders and the general
partner, in accordance with their pro rata interest, until we
distribute for each outstanding common unit an amount equal to
any arrearages in payment of the Minimum Quarterly Distribution
on the common units for any prior quarters during the
subordination period;
|
|
|
|
third, to the subordinated unitholders and the general
partner, in accordance with their pro rata interest, until we
distribute for each subordinated unit an amount equal to the
Minimum Quarterly Distribution for that quarter;
|
|
|
|
fourth, to all unitholders and the general partner, in
accordance with their pro rata interest, until each unitholder
receives a total of $0.4025 per unit for that quarter (the First
Target Distribution);
|
|
|
|
fifth, 13% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders pro rata until each unitholder receives a total of
$0.4375 per unit for that quarter (the Second Target
Distribution);
|
|
|
|
sixth, 23% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders pro rata until each unitholder receives a total of
$0.525 per unit for that quarter (the Third Target
Distribution); and
|
|
|
|
thereafter, 48% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders (the Fourth Target Distribution).
|
Distributions of Available Cash after the Subordination
Period Our partnership agreement, after
adjustment for the general partners relative ownership
level, requires that we make distributions of Available Cash
from operating surplus for any quarter after the subordination
period in the following manner:
|
|
|
|
|
first, to all unitholders and the general partner, in
accordance with their pro rata interest, until each unitholder
receives a total of $0.4025 per unit for that quarter;
|
|
|
|
second, 13% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders pro rata until each unitholder receives a total of
$0.4375 per unit for that quarter;
|
|
|
|
third, 23% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders pro rata until each unitholder receives a total of
$0.525 per unit for that quarter; and
|
|
|
|
thereafter, 48% to the general partner, plus the general
partners pro rata interest, and the remainder to all
unitholders.
|
136
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents our cash distributions paid in
2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Per Unit
|
|
|
Total Cash
|
|
Payment Date
|
|
Distribution
|
|
|
Distribution
|
|
|
|
|
|
|
(Millions)
|
|
|
November 14, 2008
|
|
$
|
0.600
|
|
|
$
|
20.1
|
|
August 14, 2008
|
|
|
0.600
|
|
|
|
20.1
|
|
May 15, 2008
|
|
|
0.590
|
|
|
|
19.6
|
|
February 14, 2008
|
|
|
0.570
|
|
|
|
15.7
|
|
November 14, 2007
|
|
|
0.550
|
|
|
|
14.7
|
|
August 14, 2007
|
|
|
0.530
|
|
|
|
12.4
|
|
May 15, 2007
|
|
|
0.465
|
|
|
|
8.6
|
|
February 14, 2007
|
|
|
0.430
|
|
|
|
7.8
|
|
November 14, 2006
|
|
|
0.405
|
|
|
|
7.4
|
|
August 14, 2006
|
|
|
0.380
|
|
|
|
6.7
|
|
May 15, 2006
|
|
|
0.350
|
|
|
|
6.3
|
|
February 13, 2006(a)
|
|
|
0.095
|
|
|
|
1.7
|
|
|
|
|
(a) |
|
Represents the pro rata portion of our Minimum Quarterly
distribution of $0.35 per unit for the period December 7,
2005, the closing of our initial public offering, through
December 31, 2005. |
|
|
13.
|
Risk
Management Activities, Credit Risk and Financial
Instruments
|
The impact of our derivative activity on our results of
operations and financial position is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Commodity cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses due to ineffectiveness
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(0.3
|
)
|
(Losses) gains reclassified into earnings
|
|
$
|
(0.8
|
)
|
|
$
|
2.4
|
|
|
$
|
2.6
|
|
Commodity derivative activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) from derivative activity
|
|
$
|
102.4
|
|
|
$
|
(81.7
|
)
|
|
$
|
0.3
|
|
Realized losses from derivative activity
|
|
$
|
(30.1
|
)
|
|
$
|
(5.9
|
)
|
|
$
|
(0.2
|
)
|
Interest rate cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Losses) gains reclassified into earnings
|
|
$
|
(6.7
|
)
|
|
$
|
0.7
|
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Commodity cash flow hedges:
|
|
|
|
|
|
|
|
|
Net deferred losses in AOCI
|
|
$
|
(1.8
|
)
|
|
$
|
(2.6
|
)
|
Interest rate cash flow hedges:
|
|
|
|
|
|
|
|
|
Net deferred losses in AOCI
|
|
$
|
(38.7
|
)
|
|
$
|
(12.3
|
)
|
For the years ended December 31, 2008, 2007 and 2006, no
derivative gains or losses were reclassified from AOCI to
current period earnings as a result of the discontinuance of
cash flow hedges related to certain forecasted transactions that
are not probable of occurring.
137
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We are exposed to market risks, including changes in commodity
prices and interest rates. We may use financial instruments such
as forward contracts, swaps and futures to mitigate the effects
of the identified risks. In general, we attempt to mitigate
risks related to the variability of future cash flows resulting
from changes in applicable commodity prices or interest rates so
that we can maintain cash flows sufficient to meet debt service,
required capital expenditures, distribution objectives and
similar requirements. We have established a comprehensive risk
management policy, or the Risk Management Policy, and a risk
management committee, to monitor and manage market risks
associated with commodity prices and interest rates. Our Risk
Management Policy prohibits the use of derivative instruments
for speculative purposes.
As of December 31, 2007, we posted collateral with certain
counterparties to our commodity derivative instruments of
approximately $18.2 million, which is included in other
current assets on the consolidated balance sheet. As of
December 31, 2008, we had an outstanding letter of credit
with a counterparty to our commodity derivative instruments of
$10.0 million. This letter of credit reduces the amount of
cash we may be required to post as collateral. As of
December 31, 2008, we had no cash collateral posted with
counterparties to our commodity derivative instruments.
Commodity Price Risk Our operations of
gathering, processing, and transporting natural gas, and the
accompanying operations of transporting and marketing of NGLs
create commodity price risk due to market fluctuations in
commodity prices, primarily with respect to the prices of NGLs,
natural gas and crude oil. As an owner and operator of natural
gas processing and other midstream assets, we have an inherent
exposure to market variables and commodity price risk. The
amount and type of price risk is dependent on the underlying
natural gas contracts to purchase and process natural gas. Risk
is also dependent on the types and mechanisms for sales of
natural gas and NGLs, and related products produced, processed,
transported or stored.
Our wholesale propane logistics business is generally designed
to establish stable margins by entering into supply arrangements
that specify prices based on established floating price indices
and by entering into sales agreements that provide for floating
prices that are tied to our variable supply costs plus a margin.
To the extent that we carry propane inventories or our sales and
supply arrangements are not aligned, we are exposed to market
variables and commodity price risk. The amount and type of price
risk is dependent on the mechanisms and locations for purchases,
sales, transportation and storage of propane.
We manage our commodity derivative activities in accordance with
our Risk Management Policy, which limits exposure to market risk
and requires regular reporting to management of potential
financial exposure.
Interest Rate Risk Interest rates on
credit facility balances and debt offerings could be higher than
current levels, causing our financing costs to increase
accordingly. Although this could limit our ability to raise
funds in the debt capital markets, we expect to remain
competitive with respect to acquisitions and capital projects,
as our competitors would face similar circumstances.
Credit Risk In the Natural Gas
Services segment, we sell natural gas to marketing affiliates of
natural gas pipelines, marketing affiliates of integrated oil
companies, marketing affiliates of DCP Midstream, LLC, national
wholesale marketers, industrial end-users and gas-fired power
plants. In the Wholesale Propane Logistics segment, we sell
primarily to retail propane distributors. In the NGL Logistics
segment, our principal customers include an affiliate of DCP
Midstream, LLC, producers and marketing companies. Concentration
of credit risk may affect our overall credit risk, in that these
customers may be similarly affected by changes in economic,
regulatory or other factors. Where exposed to credit risk, we
analyze the counterparties financial condition prior to
entering into an agreement, establish credit limits, and monitor
the appropriateness of these limits on an ongoing basis. We
operate under DCP Midstream, LLCs corporate credit policy.
DCP Midstream, LLCs corporate credit policy, as well as
the standard terms and conditions of our agreements, prescribe
the use of financial responsibility and reasonable grounds for
adequate assurances. These provisions allow our credit
department to request that a counterparty remedy credit limit
violations by posting cash or letters of credit for exposure in
excess of an established credit line. The credit line represents
an open credit limit,
138
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
determined in accordance with DCP Midstream, LLCs credit
policy and guidelines. The agreements also provide that the
inability of a counterparty to post collateral is sufficient
cause to terminate a contract and liquidate all positions. The
adequate assurance provisions also allow us to suspend
deliveries, cancel agreements or continue deliveries to the
buyer after the buyer provides security for payment to us in a
satisfactory form.
Commodity Cash Flow Protection Activities
We used NGL, natural gas and crude oil swaps
to mitigate the risk of market fluctuations in the price of
NGLs, natural gas and condensate. Prior to July 1, 2007,
the effective portion of the change in fair value of a
derivative designated as a cash flow hedge was accumulated in
AOCI. During the period in which the hedged transaction impacted
earnings, amounts in AOCI associated with the hedged transaction
were reclassified to the consolidated statements of operations
in the same accounts as the item being hedged.
Effective July 1, 2007, we elected to discontinue using the
hedge method of accounting for our commodity cash flow hedges.
Therefore, we are using the mark-to-market method of accounting
for all commodity derivative instruments. As a result, the
remaining net loss deferred in AOCI will be reclassified to
sales of natural gas, propane, NGLs and condensate, through
December 2011, as the underlying transactions impact earnings.
As of December 31, 2008, deferred net losses of
$0.9 million are expected to be reclassified during the
next 12 months. Subsequent to July 1, 2007, the
changes in fair value of financial derivatives are included in
gains and losses from derivative activity in the consolidated
statements of operations. The agreements are with major
financial institutions, which management expects to fully
perform under the terms of the agreements.
As of December 31, 2008, we have mitigated a significant
portion of our expected natural gas, NGL and condensate
commodity price risk associated with the equity volumes from our
gathering and processing operations through 2013 with natural
gas, NGLs and crude oil derivatives.
Other Asset-Based Activity To the
extent possible, we match the pricing of our supply portfolio to
our sales portfolio in order to lock in value and reduce our
overall commodity price risk. We manage the commodity price risk
of our supply portfolio and sales portfolio with both physical
and financial transactions. We occasionally will enter into
financial derivatives to lock in price variability across the
Pelico system to maximize the value of pipeline capacity. These
financial derivatives are accounted for using mark-to-market
accounting with changes in fair value recognized in current
period earnings.
Our wholesale propane logistics business is generally designed
to establish stable margins by entering into supply arrangements
that specify prices based on established floating price indices
and by entering into sales agreements that provide for floating
prices that are tied to our variable supply costs plus a margin.
Occasionally, we may enter into fixed price sales agreements in
the event that a retail propane distributor desires to purchase
propane from us on a fixed price basis. We manage this risk with
both physical and financial transactions, sometimes using
non-trading derivative instruments, which generally allow us to
swap our fixed price risk to market index prices that are
matched to our market index supply costs. In addition, we may on
occasion use financial derivatives to manage the value of our
propane inventories. These financial derivatives are accounted
for using mark-to-market accounting with changes in fair value
recognized in current period earnings.
Commodity Fair Value Hedges
Historically, we used fair value hedges to
mitigate risk to changes in the fair value of an asset or a
liability (or an identified portion thereof) that is
attributable to fixed price risk. We may hedge producer price
locks (fixed price gas purchases) to reduce our cash flow
exposure to fixed price risk by swapping the fixed price risk
for a floating price position (New York Mercantile Exchange or
index-based).
Normal Purchases and Normal Sales If a
contract qualifies and is designated as a normal purchase or
normal sale, no recognition of the contracts fair value in
the consolidated financial statements is required until
139
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the associated delivery period impacts earnings. We have applied
this accounting election for contracts involving the purchase or
sale of commodities in future periods as well as select
operating expense contracts.
Interest Rate Cash Flow Hedges We
mitigate a portion of our interest rate risk with interest rate
swaps, which reduce our exposure to market rate fluctuations by
converting variable interest rates to fixed interest rates.
These interest rate swap agreements convert the interest rate
associated with an aggregate of $575.0 million of the
indebtedness outstanding under our revolving credit facility to
a fixed rate obligation, thereby reducing the exposure to market
rate fluctuations. All interest rate swap agreements have been
designated as cash flow hedges, and effectiveness is determined
by matching the principal balance and terms with that of the
specified obligation. The effective portions of changes in fair
value are recognized in AOCI in the consolidated balance sheets.
As of December 31, 2008, $16.0 million of deferred net
losses on derivative instruments in AOCI are expected to be
reclassified into earnings during the next 12 months as the
hedged transactions impact earnings. However, due to the
volatility of the interest rate markets, the corresponding value
in AOCI is subject to change prior to its reclassification into
earnings. Ineffective portions of changes in fair value are
recognized in earnings. $425.0 million of the agreements
reprice prospectively approximately every 90 days and the
remaining $150.0 million of the agreements reprice
prospectively approximately every 30 days. Under the terms
of the interest rate swap agreements, we pay fixed rates ranging
from 2.26% to 5.19%, and receive interest payments based on the
three-month LIBOR. The differences to be paid or received under
the interest rate swap agreements are recognized as an
adjustment to interest expense. The agreements are with major
financial institutions, which are expected to fully perform
under the terms of the agreements.
|
|
14.
|
Equity-Based
Compensation
|
Total compensation (credit) cost for equity-based arrangements
was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Performance Units
|
|
$
|
(0.7
|
)
|
|
$
|
1.1
|
|
|
$
|
0.2
|
|
Phantom Units
|
|
|
(0.4
|
)
|
|
|
0.6
|
|
|
|
0.4
|
|
Restricted Phantom Units
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total compensation (credit) cost
|
|
$
|
(1.0
|
)
|
|
$
|
1.7
|
|
|
$
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On November 28, 2005, the board of directors of our General
Partner adopted a long-term incentive plan, or LTIP, for
employees, consultants and directors of our General Partner and
its affiliates who perform services for us, effective as of
December 7, 2005. Under the LTIP, equity-based instruments
may be granted to our key employees. The LTIP provides for the
grant of limited partner units, or LPUs, phantom units, unit
options and substitute awards, and, with respect to unit options
and phantom units, the grant of dividend equivalent rights, or
DERs. Subject to adjustment for certain events, an aggregate of
850,000 LPUs may be delivered pursuant to awards under the LTIP.
Awards that are canceled or forfeited, or are withheld to
satisfy the General Partners tax withholding obligations,
are available for delivery pursuant to other awards. The LTIP is
administered by the compensation committee of the General
Partners board of directors. All awards are subject to
cliff vesting, with the exception of the Phantom Units issued to
directors in conjunction with our initial public offering, which
are subject to graded vesting provisions.
All awards are accounted for as liability awards.
Performance Units We have awarded
phantom LPUs, or Performance Units, pursuant to the LTIP to
certain employees. Performance Units generally vest in their
entirety at the end of a three year performance period. The
number of Performance Units that will ultimately vest range from
0% to 200% of the outstanding Performance Units, depending on
the achievement of specified performance targets over three year
140
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
performance periods. The final performance payout is determined
by the compensation committee of the board of directors of our
General Partner. The DERs will be paid in cash at the end of the
performance period. Of the remaining Performance Units
outstanding at December 31, 2008, 21,705 units vested
in January 2009, 15,101 units are expected to vest on
December 31, 2009, and 8,544 units are expected to
vest on December 31, 2010.
At December 31, 2008, there was approximately
$0.3 million of unrecognized compensation expense related
to the Performance Units that is expected to be recognized over
a weighted-average period of 0.7 years. The following table
presents information related to the Performance Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Measurement
|
|
|
|
|
|
|
Average Price
|
|
|
Date Price
|
|
|
|
Units
|
|
|
per Unit
|
|
|
per Unit
|
|
|
Outstanding at January 1, 2006
|
|
|
|
|
|
$
|
|
|
|
|
|
|
Granted
|
|
|
40,560
|
|
|
$
|
26.96
|
|
|
|
|
|
Forfeited
|
|
|
(17,470
|
)
|
|
$
|
26.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
23,090
|
|
|
$
|
26.96
|
|
|
|
|
|
Granted
|
|
|
29,610
|
|
|
$
|
37.29
|
|
|
|
|
|
Forfeited
|
|
|
(5,740
|
)
|
|
$
|
31.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
46,960
|
|
|
$
|
32.93
|
|
|
|
|
|
Granted
|
|
|
17,085
|
|
|
$
|
33.85
|
|
|
|
|
|
Forfeited
|
|
|
(12,025
|
)
|
|
$
|
32.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
52,020
|
|
|
$
|
33.35
|
|
|
$
|
9.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest(a)
|
|
|
45,350
|
|
|
$
|
31.70
|
|
|
$
|
9.40
|
|
|
|
|
(a) |
|
Based on our December 31, 2008 estimated achievement of
specified performance targets, the performance target for units
granted in 2008 is 100%, for units granted in 2007 is 102%, and
for units granted in 2006 is 140.4%. The estimated forfeiture
rate for units granted in 2008 and 2007 is 50%, and for units
granted in 2006 is 0%. |
The estimate of Performance Units that are expected to vest is
based on highly subjective assumptions that could potentially
change over time, including the expected forfeiture rate and
achievement of performance targets. Therefore, the amount of
unrecognized compensation expense noted above does not
necessarily represent the value that will ultimately be realized
in our consolidated statements of operations.
Phantom Units In conjunction with our
initial public offering, in January 2006 our General
Partners board of directors awarded phantom LPUs, or
Phantom Units, to key employees, and to directors who are not
officers or employees of affiliates of the General Partner. The
remaining Phantom Units outstanding at December 31, 2008
vested on January 3, 2009.
In 2007, we granted 4,500 Phantom Units, pursuant to the LTIP,
to directors who are not officers or employees of affiliates of
the General Partner as part of their annual director fees for
2007. Of these units, 4,000 units vested during 2007 and
500 units vested in February 2008.
In 2008, we granted 4,000 Phantom Units, pursuant to the LTIP,
to directors who are not officers or employees of affiliates of
the General Partner as part of their annual director fees for
2008. All of these units vested during 2008.
The DERs are paid quarterly in arrears.
141
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents information related to the Phantom
Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Measurement
|
|
|
|
|
|
|
Average Price
|
|
|
Date Price
|
|
|
|
Units
|
|
|
per Unit
|
|
|
per Unit
|
|
|
Outstanding at January 1, 2006
|
|
|
|
|
|
$
|
|
|
|
|
|
|
Granted
|
|
|
35,900
|
|
|
$
|
24.05
|
|
|
|
|
|
Forfeited
|
|
|
(11,200
|
)
|
|
$
|
24.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
24,700
|
|
|
$
|
24.05
|
|
|
|
|
|
Granted
|
|
|
4,500
|
|
|
$
|
42.90
|
|
|
|
|
|
Forfeited
|
|
|
(2,333
|
)
|
|
$
|
24.05
|
|
|
|
|
|
Vested
|
|
|
(6,668
|
)
|
|
$
|
35.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
20,199
|
|
|
$
|
24.56
|
|
|
|
|
|
Granted
|
|
|
4,000
|
|
|
$
|
35.88
|
|
|
|
|
|
Forfeited
|
|
|
(4,000
|
)
|
|
$
|
24.05
|
|
|
|
|
|
Vested
|
|
|
(6,501
|
)
|
|
$
|
32.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
13,698
|
|
|
$
|
24.05
|
|
|
$
|
9.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest
|
|
|
13,698
|
|
|
$
|
24.05
|
|
|
$
|
9.40
|
|
The estimate of Phantom Units that are expected to vest is based
on highly subjective assumptions that could potentially change
over time, including the expected forfeiture rate.
Restricted Phantom Units Our General
Partners board of directors awarded restricted phantom
LPUs, or RPUs, to key employees under the LTIP. The RPUs
outstanding at December 31, 2008 are expected to vest on
December 31, 2011. The DERs are paid quarterly in arrears.
At December 31, 2008, there was approximately
$0.2 million of unrecognized compensation expense related
to the RPUs that is expected to be recognized over a
weighted-average period of 2.0 years. The following table
presents information related to the RPUs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Measurement
|
|
|
|
|
|
|
Average Price
|
|
|
Date Price
|
|
|
|
Units
|
|
|
per Unit
|
|
|
per Unit
|
|
|
Outstanding at January 1, 2008
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Granted
|
|
|
17,085
|
|
|
$
|
33.85
|
|
|
|
|
|
Forfeited
|
|
|
(2,395
|
)
|
|
$
|
35.88
|
|
|
|
|
|
Vested
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
14,690
|
|
|
$
|
33.52
|
|
|
$
|
9.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest
|
|
|
8,544
|
|
|
$
|
33.85
|
|
|
$
|
9.40
|
|
The estimate of RPUs that are expected to vest is based on
highly subjective assumptions that could potentially change over
time, including the expected forfeiture rate, which was
estimated at 50% as of December 31, 2008. Therefore, the
amount of unrecognized compensation expense noted above does not
necessarily represent the value that will ultimately be realized
in our consolidated statements of operations.
We intend to settle certain awards issued under the LTIP in cash
upon vesting. Compensation expense on these awards is recognized
ratably over each vesting period, and will be remeasured each
reporting period for
142
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
all awards outstanding until the units are vested. The fair
value of all awards is determined based on the closing price of
our common units at each measurement date.
We are structured as a master limited partnership, which is a
pass-through entity for federal income tax purposes.
Accordingly, we had no deferred tax balances as of
December 31, 2008, 2007 and 2006, and no federal income tax
expense for the years ended December 31, 2008, 2007 and
2006.
The State of Texas imposes a margin tax that is assessed at 1%
of taxable margin apportioned to Texas. Accordingly, we have
recorded current tax expense for the Texas margin tax beginning
in 2007. During 2008 we acquired properties in Michigan.
Michigan imposes a business tax of 0.8% on gross receipts, and
4.95% of Michigan taxable income. The sum of the gross receipts
and income tax is subject to a tax surcharge of 21.99%. Michigan
provides tax credits that may reduce our final tax liability.
Income tax expense for the years ended December 31, 2008
and 2007, consisted of current expense of $0.1 million for
both periods, related primarily to the Texas margin tax. We did
not have income tax expense in 2006. Our effective tax rate
differs from statutory rates, primarily due to being structured
as a limited partnership, which is a pass-through entity for
United States income tax purposes, while being treated as a
taxable entity in certain states.
|
|
16.
|
Net
Income or Loss per Limited Partner Unit
|
Our net income or loss is allocated to the general partner and
the limited partners, including the holders of the subordinated
units, in accordance with their respective ownership
percentages, after giving effect to income or loss allocated to
predecessor operations and incentive distributions paid to the
general partner.
Securities that meet the definition of a participating security
are required to be considered for inclusion in the computation
of basic earnings per unit using the two-class method. Under the
two-class method, earnings per unit is calculated as if all of
the earnings for the period were distributed under the terms of
the partnership agreement, regardless of whether the general
partner has discretion over the amount of distributions to be
made in any particular period, whether those earnings would
actually be distributed during a particular period from an
economic or practical perspective, or whether the general
partner has other legal or contractual limitations on its
ability to pay distributions that would prevent it from
distributing all of the earnings for a particular period.
These required disclosures do not impact our overall net income
or loss or other financial results; however, in periods in which
aggregate net income exceeds the First Target Distribution
Level, it will have the impact of reducing net income per LPU.
This result occurs as a larger portion of our aggregate
earnings, as if distributed, is allocated to the incentive
distribution rights of the general partner, even though we make
distributions on the basis of Available Cash and not earnings.
In periods in which our aggregate net income does not exceed the
First Target Distribution Level, there is no impact on our
calculation of earnings per LPU. During the year ended
December 31, 2008, our aggregate net income per limited
partner unit exceeded the Fourth Target Distribution level, and
as a result we allocated an additional $24.8 million in
additional earnings to the general partner. During the year
ended December 31, 2007, no additional earnings were
allocated to the general partner. During the year ended
December 31, 2006, our aggregate net income per limited
partner unit exceeded the Second Target Distribution level, and
as a result we allocated $1.3 million in additional
earnings to the general partner.
Basic and diluted net income or loss per LPU is calculated by
dividing limited partners interest in net income or loss,
less pro forma general partner incentive distributions as
described above, by the weighted-average number of outstanding
LPUs during the period.
143
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table illustrates our calculation of net income
per LPU:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Net income (loss)
|
|
$
|
125.7
|
|
|
$
|
(15.8
|
)
|
|
$
|
61.9
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to predecessor operations
|
|
|
|
|
|
|
(3.6
|
)
|
|
|
(26.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to the partnership
|
|
|
125.7
|
|
|
|
(19.4
|
)
|
|
|
35.3
|
|
Less: General partner interest in net income
|
|
|
(11.9
|
)
|
|
|
(2.2
|
)
|
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income or net loss
|
|
|
113.8
|
|
|
|
(21.6
|
)
|
|
|
34.6
|
|
Less: Additional earnings allocation to general partner
|
|
|
(24.8
|
)
|
|
|
|
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to limited partners
|
|
$
|
89.0
|
|
|
$
|
(21.6
|
)
|
|
$
|
33.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per LPU basic and diluted
|
|
$
|
3.25
|
|
|
$
|
(1.05
|
)
|
|
$
|
1.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17.
|
Commitments
and Contingent Liabilities
|
Litigation
Driver In August 2007, Driver Pipeline
Company, Inc., or Driver, filed a lawsuit against DCP Midstream,
LP, an affiliate of the owner of our general partner, in
District Court, Jackson County, Texas. The litigation stems from
an ongoing commercial dispute involving the construction of our
Wilbreeze pipeline, which was completed in December 2006. Driver
was the primary contractor for construction of the pipeline and
the construction process was managed for us by DCP Midstream,
LP. Driver claims damages in the amount of $2.4 million for
breach of contract. We believe Drivers position in this
litigation is without merit and we intend to vigorously defend
ourselves against this claim. It is not possible to predict
whether we will incur any liability or to estimate the damages,
if any, we might incur in connection with this matter.
Management does not believe the ultimate resolution of this
issue will have a material adverse effect on our consolidated
results of operations, financial position or cash flows.
El Paso On February 27, 2009, a
jury in the District Count, Harris County, Texas rendered a
verdict in favor of El Paso E&P Company, L.P. and
against one of our subsidiaries and DCP Midstream. As previously
disclosed, the lawsuit, filed in December 2006, stems from an
ongoing commercial dispute involving our Minden processing plant
that dates back to August 2000, which includes periods of time
prior to our ownership of this asset. Our responsibility for
this judgment will be limited to the time period after we
acquired the asset from DCP Midstream in December 2005. We
intend to appeal this decision and will continue to defend
ourselves vigorously against this claim. Nevertheless, as a
result of the jury verdict we have reserved a contingent
liability of $2.5 million for this matter, which is
included in our consolidated financial statements for the year
ended December 31, 2008.
Other We are not a party to any other
significant legal proceedings, but are a party to various
administrative and regulatory proceedings and commercial
disputes that have arisen in the ordinary course of our
business. Management currently believes that the ultimate
resolution of the foregoing matters, taken as a whole, and after
consideration of amounts accrued, insurance coverage or other
indemnification arrangements, will not have a material adverse
effect on our consolidated results of operations, financial
position, or cash flows.
Insurance We contract with a third
party insurer for our primary general liability insurance
covering third party exposures. DCP Midstream, LLC provides our
remaining insurance coverage through third party insurers for:
(1) statutory workers compensation insurance;
(2) automobile liability insurance for all owned,
144
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
non-owned and hired vehicles; (3) excess liability
insurance above the established primary limits for general
liability and automobile liability insurance; and
(4) property insurance, which covers replacement value of
all real and personal property and includes business
interruption/ extra expense and (5) directors and officers
insurance covering our directors and officers for acts related
to our business activities. All coverage is subject to certain
limits and deductibles, the terms and conditions of which are
common for companies with similar types of operations.
Environmental The operation of
pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs
and other products is subject to stringent and complex laws and
regulations pertaining to health, safety and the environment. As
an owner or operator of these facilities, we must comply with
United States laws and regulations at the federal, state and
local levels that relate to air and water quality, hazardous and
solid waste management and disposal, and other environmental
matters. The cost of planning, designing, constructing and
operating pipelines, plants, and other facilities must
incorporate compliance with environmental laws and regulations
and safety standards. Failure to comply with these laws and
regulations may trigger a variety of administrative, civil and
potentially criminal enforcement measures, including citizen
suits, which can include the assessment of monetary penalties,
the imposition of remedial requirements, and the issuance of
injunctions or restrictions on operation. Management believes
that, based on currently known information, compliance with
these laws and regulations will not have a material adverse
effect on our consolidated results of operations, financial
position or cash flows.
Indemnification DCP Midstream, LLC has
indemnified us for certain potential environmental claims,
losses and expenses associated with the operation of the assets
of certain of our predecessors. See the
Indemnification section of Note 5 for
additional details.
Other Commitments and Contingencies We
utilize assets under operating leases in several areas of
operation. Consolidated rental expense, including leases with no
continuing commitment, totaled $12.9 million,
$11.4 million and $11.2 million for the years ended
December 31, 2008, 2007 and 2006, respectively. Rental
expense for leases with escalation clauses is recognized on a
straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in
the year indicated are as follows at December 31, 2008:
|
|
|
|
|
|
|
(Millions)
|
|
|
2009
|
|
$
|
12.4
|
|
2010
|
|
|
9.0
|
|
2011
|
|
|
7.9
|
|
2012
|
|
|
7.0
|
|
2013
|
|
|
5.8
|
|
Thereafter
|
|
|
2.6
|
|
|
|
|
|
|
Total minimum rental payments
|
|
$
|
44.7
|
|
|
|
|
|
|
Our operations are located in the United States and are
organized into three reporting segments: (1) Natural Gas
Services; (2) Wholesale Propane Logistics; and (3) NGL
Logistics.
Natural Gas Services The Natural Gas
Services segment consists of (1) our Northern Louisiana
natural gas gathering, processing and transportation system;
(2) our Southern Oklahoma system, acquired in May 2007;
(3) our 25% limited liability company interest in East
Texas, our 40% limited liability company interest in Discovery,
and the Swap, acquired in July 2007; (4) our Colorado and
Wyoming systems, acquired in August 2007; and (5) our
Michigan systems, acquired in October 2008.
145
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Wholesale Propane Logistics The
Wholesale Propane Logistics segment consists of six owned rail
terminals, one of which was idled in 2007 to consolidate our
operations, one leased marine terminal, one pipeline terminal
and access to several open access pipeline terminals.
NGL Logistics The NGL Logistics
segment consists of the Seabreeze and Wilbreeze NGL
transportation pipelines, and a non-operated 45% equity interest
in the Black Lake interstate NGL pipeline. Prior to
December 7, 2005, our equity interest was 50%. DCP
Midstream, LLC owns a 5% interest in Black Lake, effective with
the date of our initial public offering, and an affiliate of BP
PLC owns the remaining interest and is the operator of Black
Lake. The Wilbreeze transportation pipeline began operations in
December 2006.
These segments are monitored separately by management for
performance against our internal forecast and are consistent
with internal financial reporting. These segments have been
identified based on the differing products and services,
regulatory environment and the expertise required for these
operations. Gross margin is a performance measure utilized by
management to monitor the business of each segment.
The following tables set forth our segment information:
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Propane
|
|
|
NGL
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
Logistics
|
|
|
Logistics
|
|
|
Other(c)
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Total operating revenue
|
|
$
|
791.5
|
|
|
$
|
483.0
|
|
|
$
|
11.3
|
|
|
$
|
|
|
|
$
|
1,285.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin(a)
|
|
$
|
206.5
|
|
|
$
|
11.0
|
|
|
$
|
7.1
|
|
|
$
|
|
|
|
$
|
224.6
|
|
Operating and maintenance expense
|
|
|
(32.1
|
)
|
|
|
(9.9
|
)
|
|
|
(1.0
|
)
|
|
|
|
|
|
|
(43.0
|
)
|
Depreciation and amortization expense
|
|
|
(33.8
|
)
|
|
|
(1.3
|
)
|
|
|
(1.4
|
)
|
|
|
|
|
|
|
(36.5
|
)
|
General and administrative expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24.0
|
)
|
|
|
(24.0
|
)
|
Other
|
|
|
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
1.5
|
|
Earnings from equity method investments
|
|
|
33.5
|
|
|
|
|
|
|
|
0.8
|
|
|
|
|
|
|
|
34.3
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.6
|
|
|
|
5.6
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32.8
|
)
|
|
|
(32.8
|
)
|
Income tax expense(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
Non-controlling interest in income
|
|
|
(3.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
170.2
|
|
|
$
|
1.3
|
|
|
$
|
5.5
|
|
|
$
|
(51.3
|
)
|
|
$
|
125.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash derivative mark-to-market(d)
|
|
$
|
99.2
|
|
|
$
|
2.4
|
|
|
$
|
|
|
|
$
|
(0.6
|
)
|
|
$
|
101.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
36.6
|
|
|
$
|
3.3
|
|
|
$
|
0.4
|
|
|
$
|
0.7
|
|
|
$
|
41.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
146
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Propane
|
|
|
NGL
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
Logistics
|
|
|
Logistics
|
|
|
Other(c)
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Total operating revenue
|
|
$
|
404.1
|
|
|
$
|
459.6
|
|
|
$
|
9.6
|
|
|
$
|
|
|
|
$
|
873.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin(a)
|
|
$
|
16.2
|
|
|
$
|
25.5
|
|
|
$
|
4.9
|
|
|
$
|
|
|
|
$
|
46.6
|
|
Operating and maintenance expense
|
|
|
(20.9
|
)
|
|
|
(10.4
|
)
|
|
|
(0.8
|
)
|
|
|
|
|
|
|
(32.1
|
)
|
Depreciation and amortization expense
|
|
|
(21.9
|
)
|
|
|
(1.1
|
)
|
|
|
(1.4
|
)
|
|
|
|
|
|
|
(24.4
|
)
|
General and administrative expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24.1
|
)
|
|
|
(24.1
|
)
|
Earnings from equity method investments
|
|
|
38.7
|
|
|
|
|
|
|
|
0.6
|
|
|
|
|
|
|
|
39.3
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.3
|
|
|
|
5.3
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25.8
|
)
|
|
|
(25.8
|
)
|
Income tax expense(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
Non-controlling interest in income
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
11.6
|
|
|
$
|
14.0
|
|
|
$
|
3.3
|
|
|
$
|
(44.7
|
)
|
|
$
|
(15.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash derivative mark-to-market(d)
|
|
$
|
(78.3
|
)
|
|
$
|
(2.8
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(81.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
16.2
|
|
|
$
|
3.9
|
|
|
$
|
1.2
|
|
|
$
|
|
|
|
$
|
21.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Propane
|
|
|
NGL
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
Logistics
|
|
|
Logistics
|
|
|
Other(c)
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Total operating revenue
|
|
$
|
415.3
|
|
|
$
|
375.2
|
|
|
$
|
5.3
|
|
|
$
|
|
|
|
$
|
795.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin(a)
|
|
$
|
75.3
|
|
|
$
|
16.0
|
|
|
$
|
4.1
|
|
|
$
|
|
|
|
$
|
95.4
|
|
Operating and maintenance expense
|
|
|
(13.5
|
)
|
|
|
(8.6
|
)
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
(23.7
|
)
|
Depreciation and amortization expense
|
|
|
(11.1
|
)
|
|
|
(0.8
|
)
|
|
|
(0.9
|
)
|
|
|
|
|
|
|
(12.8
|
)
|
General and administrative expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21.0
|
)
|
|
|
(21.0
|
)
|
Earnings from equity method investments
|
|
|
28.9
|
|
|
|
|
|
|
|
0.3
|
|
|
|
|
|
|
|
29.2
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.3
|
|
|
|
6.3
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11.5
|
)
|
|
|
(11.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
79.6
|
|
|
$
|
6.6
|
|
|
$
|
1.9
|
|
|
$
|
(26.2
|
)
|
|
$
|
61.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash derivative mark-to-market(d)
|
|
$
|
0.1
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
6.5
|
|
|
$
|
9.4
|
|
|
$
|
11.3
|
|
|
$
|
|
|
|
$
|
27.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
147
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Millions)
|
|
|
Segment long-term assets:
|
|
|
|
|
|
|
|
|
Natural Gas Services(e)
|
|
$
|
856.4
|
|
|
$
|
710.7
|
|
Wholesale Propane Logistics
|
|
|
54.3
|
|
|
|
52.6
|
|
NGL Logistics
|
|
|
33.8
|
|
|
|
34.8
|
|
Other(f)
|
|
|
70.3
|
|
|
|
104.1
|
|
|
|
|
|
|
|
|
|
|
Total long-term assets
|
|
|
1,014.8
|
|
|
|
902.2
|
|
Current assets
|
|
|
165.2
|
|
|
|
218.5
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,180.0
|
|
|
$
|
1,120.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Gross margin consists of total operating revenues, including
commodity derivative activity, less purchases of natural gas,
propane and NGLs. Gross margin is viewed as a non-GAAP measure
under the rules of the SEC, but is included as a supplemental
disclosure because it is a primary performance measure used by
management as it represents the results of product sales versus
product purchases. As an indicator of our operating performance,
gross margin should not be considered an alternative to, or more
meaningful than, net income or cash flow as determined in
accordance with GAAP. Our gross margin may not be comparable to
a similarly titled measure of another company because other
entities may not calculate gross margin in the same manner. |
|
(b) |
|
Income tax expense in 2008 and 2007 relates primarily to the
Texas margin tax. |
|
(c) |
|
Other consists of general and administrative expense, interest
income, interest expense and income tax expense. |
|
(d) |
|
Non-cash derivative mark-to-market is included in segment gross
margin, along with cash settlements for our derivative contracts. |
|
(e) |
|
Long-term assets for our Natural Gas Services segment increased
in 2008 as a result of our acquisition of MPP in October 2008,
and in 2007 as a result of our Southern Oklahoma acquisition in
May 2007, and our acquisition of certain MEG subsidiaries in
August 2007. Long-term assets for our Natural Gas Services
segment include the effects of our 25% equity interest in East
Texas, our 40% equity interest in Discovery and the Swap
acquired in July 2007, for all periods presented. |
|
(f) |
|
Other long-term assets not allocable to segments consist of
restricted investments, unrealized gains on derivative
instruments, corporate leasehold improvements and other
long-term assets. |
148
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
19.
|
Supplemental
Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Cash paid for interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
$
|
26.3
|
|
|
$
|
26.5
|
|
|
$
|
11.1
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash additions of property, plant and equipment
|
|
$
|
1.5
|
|
|
$
|
5.9
|
|
|
$
|
1.4
|
|
Accounts payable related to acquisitions
|
|
$
|
|
|
|
$
|
9.0
|
|
|
$
|
9.9
|
|
Accrued distributions to DCP Midstream, LLC related to
reimbursements
|
|
$
|
|
|
|
$
|
0.5
|
|
|
$
|
|
|
Accrued contributions from DCP Midstream, LLC related to
reimbursements
|
|
$
|
|
|
|
$
|
0.3
|
|
|
$
|
|
|
Accrued equity-based compensation
|
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
$
|
|
|
|
|
20.
|
Quarterly
Financial Data (Unaudited)
|
Our consolidated results of operations by quarter for the years
ended December 31, 2008, 2007 and 2006 were as follows
(millions, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2008
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
2008
|
|
|
Total operating revenues
|
|
$
|
337.7
|
|
|
$
|
145.9
|
|
|
$
|
426.8
|
|
|
$
|
375.4
|
|
|
$
|
1,285.8
|
|
Operating (loss) income
|
|
$
|
(16.6
|
)
|
|
$
|
(165.7
|
)
|
|
$
|
152.4
|
|
|
$
|
152.5
|
|
|
$
|
122.6
|
|
Net (loss) income
|
|
$
|
(6.5
|
)
|
|
$
|
(159.3
|
)
|
|
$
|
152.7
|
|
|
$
|
138.8
|
|
|
$
|
125.7
|
|
Limited partners interest in net (loss) income
|
|
$
|
(8.2
|
)
|
|
$
|
(159.8
|
)
|
|
$
|
147.8
|
|
|
$
|
134.0
|
|
|
$
|
113.8
|
|
Basic net (loss) income per limited partner unit
|
|
$
|
(0.33
|
)
|
|
$
|
(5.66
|
)
|
|
$
|
2.97
|
|
|
$
|
2.72
|
|
|
$
|
3.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2007
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
2007
|
|
|
Total operating revenues
|
|
$
|
237.2
|
|
|
$
|
181.1
|
|
|
$
|
188.6
|
|
|
$
|
266.4
|
|
|
$
|
873.3
|
|
Operating income (loss)
|
|
$
|
11.5
|
|
|
$
|
(1.8
|
)
|
|
$
|
3.9
|
|
|
$
|
(47.6
|
)
|
|
$
|
(34.0
|
)
|
Net income (loss)
|
|
$
|
15.8
|
|
|
$
|
0.8
|
|
|
$
|
7.5
|
|
|
$
|
(39.9
|
)
|
|
$
|
(15.8
|
)
|
Limited partners interest in net income (loss)(a)
|
|
$
|
12.2
|
|
|
$
|
0.2
|
|
|
$
|
6.6
|
|
|
$
|
(40.6
|
)
|
|
$
|
(21.6
|
)
|
Basic net income (loss) per limited partner unit(a)
|
|
$
|
0.58
|
|
|
$
|
0.01
|
|
|
$
|
0.29
|
|
|
$
|
(1.69
|
)
|
|
$
|
(1.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2006
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
2006
|
|
|
Total operating revenues
|
|
$
|
265.4
|
|
|
$
|
160.1
|
|
|
$
|
162.8
|
|
|
$
|
207.5
|
|
|
$
|
795.8
|
|
Operating income
|
|
$
|
9.1
|
|
|
$
|
9.3
|
|
|
$
|
7.3
|
|
|
$
|
12.2
|
|
|
$
|
37.9
|
|
Net income
|
|
$
|
16.3
|
|
|
$
|
15.7
|
|
|
$
|
14.3
|
|
|
$
|
15.6
|
|
|
$
|
61.9
|
|
Limited partners interest in net income(a)(b)
|
|
$
|
5.3
|
|
|
$
|
8.6
|
|
|
$
|
9.5
|
|
|
$
|
11.1
|
|
|
$
|
34.6
|
|
Basic net income per limited partner unit(a)(b)
|
|
$
|
0.30
|
|
|
$
|
0.47
|
|
|
$
|
0.51
|
|
|
$
|
0.55
|
|
|
$
|
1.90
|
|
149
DCP
MIDSTREAM PARTNERS, LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(a) |
|
Total limited partners interest in net income and basic
income per limited partner unit excludes the results from our
interest in East Texas, Discovery and the Swap for the period
January 1, 2006 through June 30, 2007. |
|
(b) |
|
Total limited partners interest in net income and basic
income per limited partner unit excludes the results from our
wholesale propane logistics business for the period
January 1, 2006 through October 31, 2006. |
On February 27, 2009, a jury in the District Count, Harris
County, Texas rendered a verdict in favor of El Paso
E&P Company, L.P. and against one of our subsidiaries and
DCP Midstream. As previously disclosed, the lawsuit, filed in
December 2006, stems from an ongoing commercial dispute
involving our Minden processing plant that dates back to August
2000, which includes periods of time prior to our ownership of
this asset. Our responsibility for this judgment will be limited
to the time period after we acquired the asset from DCP
Midstream in December 2005. We intend to appeal this decision
and will continue to defend ourselves vigorously against this
claim. Nevertheless, as a result of the jury verdict we have
reserved a contingent liability of $2.5 million for this
matter, which is included in our consolidated financial
statements for the year ended December 31, 2008.
On February 25, 2009, we entered into a Contribution
Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC
will contribute an additional 25.1% interest in East Texas to us
in exchange for 3.5 million Class D units, providing
us with a 50.1% interest in East Texas following the expected
closing of the transaction in April 2009. This closing date is
subject to extension for up to 45 days to allow for repairs
or replacement to our reasonable satisfaction any assets
destroyed or damaged by certain casualty losses and time to
enable the plant to process all available inlet volumes as
defined in the Contribution Agreement. The Class D units
will automatically convert into common units in August 2009 and
will not be eligible to receive a distribution until the second
quarter distribution payable in August 2009. DCP Midstream, LLC
has agreed to provide a fixed-price NGL derivative by NGL
component for the period of April 2009 to March 2010 for the
acquired interest. Subsequent to this transaction, we will
consolidate East Texas in our consolidated financial statements.
On February 11, 2009, we announced, along with DCP
Midstream, LLC, that our East Texas natural gas processing
complex and residue natural gas delivery system known as the
Carthage Hub, have been temporarily shut in following a fire
that was caused by a third party underground pipeline outside of
our property line that ruptured. No employees or contractors
were injured in the incident. There was no significant damage to
the natural gas processing complex. As of February 25,
2009, the complex began processing through one of the five
plants, and it is expected that full processing capacities will
be restored for the entire complex over the next 30 days.
Residue gas will be redelivered into limited available pipeline
interconnects while the Carthage Hub undergoes inspection and
repairs.
On February 17, 2009, the remaining 3,571,429 DCP Partners
subordinated units were converted to common units following the
completion of the subordination period and satisfactory
completion of all subordination period tests contained in the
DCP Partners partnership agreement.
In February 2009, we entered into interest rate swap agreements
to convert $275.0 million of the indebtedness on our
revolving credit facility to a fixed rate obligation, thereby
reducing the exposure to interest rate fluctuations. These
interest rate swaps commence in December 2010 and expire in June
2012
On January 27, 2009, the board of directors of the General
Partner declared a quarterly distribution of $0.60 per unit,
payable on February 13, 2009 to unitholders of record on
February 6, 2009.
150
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
There were no changes in or disagreements with accountants on
accounting and financial disclosures during the year ended
December 31, 2008.
|
|
Item 9A.
|
Controls
and Procedures
|
We maintain disclosure controls and procedures that are designed
to ensure that information required to be disclosed by us in the
reports that we file or submit to the Securities and Exchange
Commission under the Securities Exchange Act of 1934, as
amended, is recorded, processed, summarized and reported within
the time periods specified by the Commissions rules and
forms, and that information is accumulated and communicated to
the management of our general partner, including our general
partners principal executive and principal financial
officers (whom we refer to as the Certifying Officers), as
appropriate to allow timely decisions regarding required
disclosure. The management of our general partner evaluated,
with the participation of the Certifying Officers, the
effectiveness of our disclosure controls and procedures as of
December 31, 2008, pursuant to
Rule 13a-15(b)
under the Exchange Act. Based upon that evaluation, the
Certifying Officers concluded that, as of December 31,
2008, our disclosure controls and procedures were effective.
There were no changes in internal control over financial
reporting (as defined in
Rule 13a-15(f)
under the Exchange Act) that occurred during the fourth quarter
of 2008 that have materially affected, or are reasonably likely
to materially affect, our internal control over financial
reporting.
Managements
Annual Report On Internal Control Over Financial
Reporting
Our general partner is responsible for establishing and
maintaining an adequate system of internal control over
financial reporting, as such term is defined in Exchange Act
Rules 13a-15(f)
and
15d-15(f).
Our internal control system was designed to provide reasonable
assurance to our management and board of directors of our
general partner regarding the preparation and fair presentation
of published financial statements.
All internal control systems, no matter how well designed, have
inherent limitations. Therefore, internal control over financial
reporting may not prevent or detect misstatements. Projections
of any evaluation of effectiveness to future periods are subject
to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with
policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief
Financial Officer, has conducted an evaluation of the
effectiveness of our internal control over financial reporting
as of December 31, 2008 based on the framework in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on that evaluation, management concluded
that our internal control over financial reporting was effective
as of December 31, 2008.
Deloitte & Touche, LLP, an independent registered
public accounting firm, has issued their report, included
immediately following, regarding our internal control over
financial reporting.
March 4, 2009
151
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream Partners GP, LLC
Denver, Colorado
We have audited the internal control over financial reporting of
DCP Midstream Partners, LP and subsidiaries (the
Company) as of December 31, 2008, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Companys
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in the accompanying Managements Annual Report On
Internal Control Over Financial Reporting. Our responsibility is
to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed by, or under the supervision of, the
companys principal executive and principal financial
officers, or persons performing similar functions, and effected
by the companys board of directors, management, and other
personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting
to future periods are subject to the risk that the controls may
become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
152
In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2008, based on the criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated financial statements and financial statement
schedule as of and for the year ended December 31, 2008 of
the Company and our report dated March 4, 2009 expressed an
unqualified opinion (including explanatory paragraphs referring
to (1) the preparation of the portion of the DCP Midstream
Partners, LP consolidated financial statements attributable to
the wholesale propane logistics business from the separate
records maintained by DCP Midstream, LLC and (2) the
preparation of the portion of the DCP Midstream Partners, LP
consolidated financial statements attributable to the DCP East
Texas Holdings, LLC, Discovery Producer Services, LLC, and a
nontrading derivative instrument from the separate records
maintained by DCP Midstream, LLC) on those financial
statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 4, 2009
153
Item 9B. Other
Information
No information was required to be disclosed in a report on
Form 8-K,
but not so reported, for the quarter ended December 31,
2008.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
Management
of DCP Midstream Partners, LP
We do not have directors or officers, which is commonly the case
with publicly traded partnerships. Our operations and activities
are managed by our general partner, DCP Midstream GP, LP, which
in turn is managed by its general partner, DCP Midstream GP,
LLC, which we refer to as our General Partner. Our General
Partner is wholly-owned by DCP Midstream, LLC. The officers and
directors of our General Partner are responsible for managing
us. All of the directors of our General Partner are elected
annually by DCP Midstream, LLC and all of the officers of our
General Partner serve at the discretion of the directors.
Unitholders are not entitled to participate, directly or
indirectly, in our management or operations.
Board of
Directors and Officers
The board of directors of our General Partner that oversees our
operations currently has nine members, four of whom are
independent as defined under the independence standards
established by the New York Stock Exchange. The New York Stock
Exchange does not require a listed limited partnership like us
to have a majority of independent directors on its general
partners board of directors or to establish a compensation
committee or a nominating committee. However, the board of
directors of our General Partner has established an audit
committee consisting of four independent members of the board, a
compensation committee and a special committee to address
conflict situations.
Our General Partners board of directors annually reviews
the independence of directors and affirmatively makes a
determination that each director expected to be independent has
no material relationship with our General Partner, either
directly or indirectly as a partner, unitholder or officer of an
organization that has a relationship with our General Partner.
The executive officers of our General Partner manage the
day-to-day affairs of our business and devote all of their time
to our business and affairs, except Mark A. Borer, our CEO and
President, who devotes more than 90% of his time to our business
and affairs. We also utilize employees of DCP Midstream, LLC to
operate our business and provide us with general and
administrative services.
Meeting
Attendance and Preparation
Members of our board of directors attended at least 75% of
regular board meetings and meetings of the committees on which
they serve, either in person or telephonically, during 2008. In
addition, directors are expected to be prepared for each meeting
of the board by reviewing materials distributed in advance.
154
Directors
and Executive Officers
The following table shows information regarding the current
directors and the executive officers of DCP Midstream GP, LLC.
Directors are elected for one-year terms.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with DCP Midstream GP, LLC
|
|
Thomas C. OConnor
|
|
|
53
|
|
|
Chairman of the Board and Director
|
Mark A. Borer
|
|
|
54
|
|
|
President, Chief Executive Officer and Director
|
Angela A. Minas
|
|
|
44
|
|
|
Vice President and Chief Financial Officer
|
Michael S. Richards
|
|
|
49
|
|
|
Vice President, General Counsel and Secretary
|
Don Baldridge
|
|
|
39
|
|
|
Vice President, Business Development
|
Paul F. Ferguson, Jr.
|
|
|
59
|
|
|
Director
|
Gregory J. Goff
|
|
|
52
|
|
|
Director
|
Alan N. Harris
|
|
|
55
|
|
|
Director
|
John E. Lowe
|
|
|
50
|
|
|
Director
|
Frank A. McPherson
|
|
|
75
|
|
|
Director
|
Thomas C. Morris
|
|
|
68
|
|
|
Director
|
Stephen R. Springer
|
|
|
62
|
|
|
Director
|
Our directors hold office for one year or until the earlier of
their death, resignation, removal or disqualification or until
their successors have been elected and qualified. Officers serve
at the discretion of the board of directors. There are no family
relationships among any of our directors or executive officers.
Thomas C. OConnor was elected Chairman of the Board
of DCP Midstream GP, LLC in September 2008, and has been a
director of DCP Midstream GP, LLC since December 2007.
Mr. OConnor has over 20 years experience in the
natural gas industry with Duke Energy prior to joining DCP
Midstream, LLC in November 2007 as Chairman of the board,
President and CEO. Mr. OConnor joined Duke Energy in
1987 where he served in a variety of positions in the
companys natural gas and pipeline operations units. After
serving in a number of leadership positions with Duke Energy, he
was named President and Chief Executive Officer of Duke Energy
Gas Transmission in 2002 and he was named Group Vice President
of corporate strategy at Duke Energy in 2005. In 2006 he became
Group Executive and Chief Operating Officer of
U.S. Franchised Electric and Gas and later in 2006 was
named Group Executive and President of Commercial Businesses at
Duke Energy.
Mark A. Borer was elected President and Chief Executive
Officer, and director of DCP Midstream GP, LLC in November 2006.
Mr. Borer was previously Group Vice President, Marketing
and Corporate Development of DCP Midstream, LLC since July 2004.
He previously served as Executive Vice President of Marketing
and Corporate Development of DCP Midstream, LLC from May 2002
through July 2004. Mr. Borer served as Senior Vice
President, Southern Division of DCP Midstream, LLC from April
1999 through May 2002. Prior to that time, Mr. Borer was
Vice President of Natural Gas Marketing for Union Pacific Fuels,
Inc.
Angela A. Minas was elected Vice President and Chief
Financial Officer of DCP Midstream GP, LLC in September 2008.
Ms. Minas was previously Chief Financial Officer, Chief
Accounting Officer and Treasurer for Constellation Energy
Partners from September 2006 through March 2008. She also served
as Managing Director of the Commodities Group at Constellation
Energy Group, Inc. from September 2006 through March 2008. Prior
to that, Ms. Minas was Senior Vice President, Global
Consulting from 2004 to 2006 for SAIC and Vice President, US
Consulting from 2002 to 2003 for SAIC. Prior to that,
Ms. Minas was a partner with Arthur Andersen LLP from 1997
through 2002.
Michael S. Richards was elected Vice President, General
Counsel and Secretary of DCP Midstream GP, LLC in September
2005. Mr. Richards was previously Assistant General Counsel
and Assistant Secretary of DCP Midstream, LLC since February
2000. He was previously Assistant General Counsel and Assistant
Secretary at KN Energy, Inc. from December 1997 until he
joined DCP Midstream, LLC. Prior to that, he was Senior Counsel
and Risk Manager at Total Petroleum (North America) Ltd. from
1994 through 1997. Mr. Richards was previously in private
practice where he focused on securities and corporate finance.
155
Don Baldridge was elected Vice President, Business
Development of DCP Midstream GP, LLC in January 2009.
Mr. Baldridge was previously Vice President, Corporate
Development of DCP Midstream, LLC since August 2008. Prior to
that, he served as senior director, corporate development and
other management positions with DCP Midstream, LLC since April
2005. Mr. Baldridge has more than 16 years experience
in the energy industry, including commercial, trading and
business development activities.
Paul F. Ferguson, Jr. was elected as a director of
DCP Midstream GP, LLC in November 2005. Mr. Ferguson was a
member of the Compensation, Audit and special committees of the
general partner of TEPPCO Partners, L.P. He served as Senior
Vice President and Treasurer of Duke Energy from June 1997 to
June 1998, when he retired. Mr. Ferguson served as Senior
Vice President and Chief Financial Officer of PanEnergy Corp.
from September 1995 to June 1997. He held various other
financial positions with PanEnergy Corp. from 1989 to 1995 and
served as Treasurer of Texas Eastern Corporation from 1988 to
1989. Mr. Ferguson was a director of the general partner of
TEPPCO Partners, L.P. from October 2004 until his resignation in
2005.
Gregory J. Goff, was elected a director of DCP Midstream
GP, LLC in October 2008, and is currently Senior Vice President,
Commercial for ConocoPhillips. Previously, Mr. Goff served
as President, Specialty Businesses and Business Development.
From 2004 to 2006, Mr. Goff served as president of
ConocoPhillips US Lower 48 and Latin American exploration
and production business. From 2002 to 2004 Mr. Goff served
as president of Europe and Asia Pacific Downstream Activities
for ConocoPhillips. From 2000 to 2002 Mr. Goff served as
Chairman and Managing Director of Conoco Limited in the United
Kingdom. From 1998 to 2000 Mr. Goff served as managing
Director and Chief Executive Officer of Conoco JET Nordic in
Stockholm, Sweden.
Alan N. Harris was appointed as a director of DCP
Midstream GP, LLC in December 2008, effective January 1,
2009; at that time he was not appointed to any committee of the
board of Directors. In January 2009, the board of directors
appointed Mr. Harris as Chairman to the compensation
committee of the board of directors. Mr. Harris currently
serves as chief development and operations officer of Spectra
Energy. Prior to Spectra Energys spin-off from Duke Energy
in 2007, Mr. Harris served as group vice president and
chief financial officer of Duke Energy Gas Transmission, or
DEGT, from February 2004 and was named executive vice president
of DEGT in December 2002. Mr. Harris, who joined the
corporation in 1982, has served in a number of other senior
management positions since that time. Mr. Harris has been
in the energy industry for over 30 years.
John E. Lowe, was elected a director of DCP Midstream GP,
LLC in October 2008, and is currently Assistant to the Chief
Executive Officer for ConocoPhillips, representing the company
in external relationships and assisting on special projects.
Mr. Lowe was previously Executive Vice President,
Exploration and Production. Mr. Lowe has also served
ConocoPhillips as Executive Vice President of Planning, Strategy
and Corporate Affairs. Senior Vice President of Corporate
Strategy and Development and was responsible for the forward
strategy, development opportunities and public relations
functions of Phillips Petroleum Company. From 1999 to 2000,
Mr. Lowe served as Vice President of Planning and Strategic
Transactions for ConocoPhillips.
Frank A. McPherson was elected as a director of DCP
Midstream GP, LLC in December 2005. Mr. McPherson retired
as Chairman and Chief Executive Officer from Kerr McGee
Corporation in 1997 after a
40-year
career with the company. Mr. McPherson was Chairman and
Chief Executive Officer of Kerr McGee from 1983 to 1997. Prior
to that he served in various capacities in management of Kerr
McGee. Mr. McPherson joined Kerr McGee in 1957.
Mr. McPherson previously served on the boards of Integris
Health, Tri Continental Corporation, Seligman Group of Mutual
Funds, ConocoPhillips, Kimberly Clark Corporation, MAPCO Inc.,
Bank of Oklahoma, the Federal Reserve Bank of Kansas City, the
Oklahoma State University Foundation Board of Trustees, the
American Petroleum Institute, and several non-profit
organizations in Oklahoma.
Thomas C. Morris was elected as a director of DCP
Midstream GP, LLC in December 2005. Mr. Morris is currently
retired, having served 34 years with Phillips Petroleum
Company. Mr. Morris served in various capacities with
Phillips, including Vice President and Treasurer and
subsequently Senior Vice President and
156
Chief Financial Officer from 1994 until his retirement in 2001.
Mr. Morris served as Vice Chairman of the board of OK
Mozart, is a former member of the executive board of the
American Petroleum Institute finance committee and a former
member of the Business Development Council of Texas A&M
University.
Stephen R. Springer was elected as a director of DCP
Midstream GP, LLC in July 2007. Mr. Springer has over
thirty years experience in the energy industry. He began his
career at Texas Gas Transmission Corporation, where he served in
a variety of executive management positions within gas
acquisitions and gas marketing. After serving as President of
Transco Gas Marketing Company, he served as Vice President of
Business Development at Williams Field Services Company and then
Senior Vice President and General Manager of Williams Midstream
Division, the position he held until his retirement in 2002.
Mr. Springer has served on the board of directors of Atmos
Energy Corporation since 2005.
Section 16(a)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires DCP Midstream GP, LLCs directors and executive
officers, and persons who own more than 10% of any class of our
equity securities to file with the Securities and Exchange
Commission, or SEC, and the New York Stock Exchange initial
reports of ownership and reports of changes in ownership of our
common units and our other equity securities. Specific due dates
for those reports have been established, and we are required to
report herein any failure to file reports by those due dates.
Directors, executive officers and greater than 10% unitholders
are also required by SEC regulations to furnish us with copies
of all Section 16(a) reports they file. To our knowledge,
based solely on a review of the copies of reports furnished to
us and written representations that no other reports were
required during the fiscal year ended December 31, 2008,
all Section 16(a) filing requirements applicable to such
reporting persons were complied with, except that a late
Form 4 was filed for Ms. Minas in January 2009
reflecting the granted phantom units dated October 1, 2008,
following her employment by the Partnership.
Audit
Committee
The board of directors of our General Partner has a standing
audit committee. The audit committee is composed of four
nonmanagement directors, Paul F. Ferguson, Jr. (chairman),
Frank A. McPherson, Thomas C. Morris and Stephen R. Springer,
each of whom is able to understand fundamental financial
statements and at least one of whom has past experience in
accounting or related financial management experience. The board
has determined that each member of the audit committee is
independent under Section 303A.02 of the New York Stock
Exchange listing standards and Section 10A(m)(3) of the
Securities Exchange Act of 1934, as amended. In making the
independence determination, the board considered the
requirements of the New York Stock Exchange and our Code of
Business Ethics. Among other factors, the board considered
current or previous employment with us, our auditors or their
affiliates by the director or his immediate family members,
ownership of our voting securities, and other material
relationships with us. The audit committee has adopted a
charter, which has been ratified and approved by the board of
directors.
With respect to material relationships, the following
relationships are not considered to be material for purposes of
assessing independence: service as an officer, director,
employee or trustee of, or greater than five percent beneficial
ownership in (a) a supplier to the partnership if the
annual sales to the partnership are less than one percent of the
sales of the supplier; (b) a lender to the partnership if
the total amount of the partnerships indebtedness is less
than one percent of the total consolidated assets of the lender;
or (c) a charitable organization if the total amount of the
partnerships annual charitable contributions to the
organization are less than three percent of that
organizations annual charitable receipts.
Mr. Ferguson has been designated by the board as the audit
committees financial expert meeting the requirements
promulgated by the SEC and set forth in Item 407(d) of
Regulation S-K
of the Securities Exchange Act of 1934 based upon his education
and employment experience as more fully detailed in
Mr. Fergusons biography set forth above.
157
Special
Committee
The board of directors of our General Partner has a standing
special committee, which is comprised of four nonmanagement
directors, Stephen R. Springer (chairman), Paul F.
Ferguson, Jr., Frank A. McPherson and Thomas C. Morris. The
special committee will review specific matters that the board
believes may involve conflicts of interest. The special
committee will determine if the resolution of the conflict of
interest is fair and reasonable to us. The special committee
meets at each quarterly meeting of the Board of Directors. The
members of the special committee may not be officers or
employees of our General Partner or directors, officers or
employees of its affiliates. Each of the members of the special
committee meet the independence and experience standards
established by the New York Stock Exchange and the Securities
Exchange Act of 1934, as amended. Any matters approved by the
special committee will be conclusively deemed to be fair and
reasonable to us, approved by all of our partners, and not a
breach by our General Partner of any duties it may owe us or our
unitholders.
Compensation
Committee
The board of directors of our General Partner has a standing
compensation committee, which is composed of four directors,
Alan N. Harris (chairman), Gregory J. Goff, Thomas C.
OConnor and Frank A. McPherson. The compensation committee
oversees compensation decisions for the officers of our general
partner and administers the long-term incentive plan, selecting
individuals to be granted equity-based awards from among those
eligible to participate. The compensation committee has adopted
a charter, which has been ratified and approved by the board of
directors.
Corporate
Governance Guidelines and Code of Business Ethics
Our board of directors has adopted Corporate Governance
Guidelines that outline the important policies and practices
regarding our governance.
We have adopted a Code of Business Ethics applicable to the
persons serving as our directors, officers (including without
limitation, the chief executive officer, chief financial officer
and principal accounting officer) and employees, which includes
the prompt disclosure to the SEC of a current report on
Form 8-K
of any waiver of the code for executive officers or directors
approved by the board of directors.
Copies of our Corporate Governance Guidelines, our Code of
Business Ethics, our Audit Committee Charter and our
Compensation Committee Charter are available on our website at
www.dcppartners.com. Copies of these items are also
available free of charge in print to any unitholder who sends a
request to the office of the Secretary of DCP Midstream
Partners, LP at 370 17th Street, Suite 2775, Denver,
Colorado 80202.
Meeting
of Non-Management Directors and Communications with
Directors
At each quarterly meeting of the special committee, the
committee, which consists of all of our non-management
directors, meets in an executive session without management
participation or participation by non-independent directors. The
chairman of the special committee presides over these executive
sessions.
Unitholders or interested parties may communicate with any and
all members of our board, including our nonmanagement directors,
or any committee of our board, by transmitting correspondence by
mail or facsimile addressed to one or more directors by name or
to the chairman of the board or any committee of the board at
the following address and fax number; Name of the Director(s),
c/o Secretary,
DCP Midstream Partners, LP, 370
17th Street,
Suite 2775, Denver, Colorado 80202,
(303) 633-2921.
New York
Stock Exchange, or NYSE, Annual Certification
On March 26, 2008, Mark A. Borer, our Chief Executive
Officer, certified to the NYSE, as required by NYSE rules, that
as of March 26, 2008, he was not aware of any violation by
us of the NYSEs Corporate Governance Listing Standards.
158
Report of
the Audit Committee
The audit committee oversees our financial reporting process on
behalf of the board of directors. Management has the primary
responsibility for the financial statements and the reporting
process including the systems of internal controls. The audit
committee operates under a written charter approved by the board
of directors. The charter, among other things, provides that the
audit committee has authority to appoint, retain and oversee the
independent auditor. In this context, the audit committee:
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reviewed and discussed the audited financial statements in this
annual report on
Form 10-K
with management, including a discussion of the quality, not just
the acceptability, of the accounting principles, the
reasonableness of significant judgments and the clarity of
disclosures in the financial statements;
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reviewed with Deloitte & Touche, LLP, our independent
auditors, who are responsible for expressing an opinion on the
conformity of those audited financial statements with generally
accepted accounting principles, their judgments as to the
quality and acceptability of our accounting principles and such
other matters as are required to be discussed with the audit
committee under generally accepted auditing standards;
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received the written disclosures and the letter required by
standard No. 1 of the independence standards board
(independence discussions with audit committees) provided to the
audit committee by Deloitte & Touche, LLP;
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discussed with Deloitte & Touche, LLP its independence
from management and us and considered the compatibility of the
provision of nonaudit service by the independent auditors with
the auditors independence;
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discussed with Deloitte & Touche, LLP the matters
required to be discussed by statement on auditing standards
No. 61 (communications with audit committees);
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discussed with our internal auditors and Deloitte &
Touche, LLP the overall scope and plans for their respective
audits. The audit committee meets with the internal auditors and
Deloitte & Touche, LLP, with and without management
present, to discuss the results of their examinations, their
evaluations of our internal controls and the overall quality of
our financial reporting;
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based on the foregoing reviews and discussions, recommended to
the board of directors that the audited financial statements be
included in the annual report on
Form 10-K
for the year ended December 31, 2008, for filing with the
Securities and Exchange Commission; and
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approved the selection and appointment of Deloitte &
Touche, LLP to serve as our independent auditors.
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This report has been furnished by the members of the audit
committee of the board of directors:
Audit Committee
Paul F. Ferguson, Jr. (Chairman)
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
The report of the audit committee in this report shall not be
deemed incorporated by reference into any other filing by DCP
Midstream Partners, LP under the Securities Act of 1933, as
amended, or the Securities Exchange Act of 1934, except to the
extent that we specifically incorporate this information by
reference, and shall not otherwise be deemed filed under such
acts.
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Item 11.
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Executive
Compensation
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Compensation
Discussion and Analysis
General
As a publicly traded limited partnership, we do not have
directors, officers or employees. Instead, our operations are
managed by our general partner, DCP Midstream GP, LP, which in
turn is managed by its general partner, DCP Midstream GP, LLC,
which we refer to as our General Partner. Our General Partner is
a wholly-owned subsidiary of DCP Midstream, LLC.
As of February 23, 2009, our General Partner has four
executive officers and six additional employees. All of these
employees are solely dedicated to our operations and management,
except our President and Chief Executive Officer, or CEO, who
devotes more than 90% of his time to our operations and
management. The General Partner has not entered into employment
agreements with any of our executive officers. The compensation
committee of our General Partners board of directors
establishes the compensation program for these employees.
Compensation
Committee
The compensation committee is comprised of directors of our
General Partner and has four members as of February 23,
2009. The compensation committees responsibilities
include, among other duties, the following:
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annually review and approve Partnership goals and objectives
relevant to compensation of the CEO and other executive officers;
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annually evaluate the CEOs performance in light of the
Partnership goals and objectives, and approve the compensation
levels for the CEO and other executive officers;
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periodically evaluate the terms and administration of the
Partnerships short-term and long-term incentive plans to
assure that they are structured and administered in a manner
consistent with the Partnerships goals and objectives;
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periodically evaluate incentive compensation and equity-related
plans and consider amendments if appropriate;
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retain and terminate any compensation consultant to be used to
assist in the evaluation of director, CEO or executive officer
compensation; and
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perform other duties as deemed appropriate by the General
Partners board of directors.
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Compensation
Philosophy
Our compensation program is structured to provide the following
benefits:
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Attract, retain and reward talented executive officers and key
management employees by providing total compensation competitive
with that of other executive officers and key management
employees employed by publicly traded limited partnerships of
similar size or in similar lines of business;
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Motivate executive officers and key management employees to
achieve strong financial and operational performance;
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Emphasize performance-based compensation, balancing short-term
and long-term results;
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Reward individual performance; and
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Encourage a long-term commitment to the Partnership by requiring
target levels of unit ownership.
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Methodology
The compensation committee reviews data from market surveys
provided by independent consultants to assess the competitive
position with respect to base salary, annual short-term
incentives and long-term incentive compensation. With respect to
executive officer compensation, the compensation committee also
considers individual performance, levels of responsibility,
skills and experience. In 2008 we engaged the services of BDO
Seidman, LLP, or BDO, a compensation consultant, to conduct a
study to assist us in establishing overall compensation packages
for our executives. The study was based on compensation as
reported in the annual reports on
Form 10-K
for a group of peer companies with a similar tax status, and the
2008 Towers Perrin General Industry Executive Compensation
Database, or the Towers Perrin Database. The study was comprised
of the following peer companies: Boardwalk Pipeline Partners,
LP, Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex
Energy, L.P., Enbridge Energy Partners, L.P., Genesis Energy,
L.P., Magellan Midstream Partners, L.P., MarkWest Energy
Partners, L.P., NuStar Energy L.P., ONEOK Partners, L.P., Plains
All American Pipeline, L.P., Regency Energy Partners LP, Spectra
Energy Partners, LP, Sunoco Logistics Partners L.P., Targa
Resources Partners LP and TEPPCO Partners LP. Studies such as
this generally include only the most highly compensated officers
of each company, which correlates with our executive officers.
The results of this study, as well as other factors such as our
targeted performance objectives, served as a benchmark for
establishing our total direct compensation packages. In order to
assess the competitiveness of the total direct compensation
packages for our executive officers we used the median amount
for peer positions from the BDO study and the data point that
represents the 50th percentile of the market in the Towers
Perrin Database.
Components
of Compensation
The total annual direct compensation program for executives of
the General Partner consists of three components: (1) base
salary; (2) an annual short-term cash incentive, or STI,
which is based on a percentage of annual base salary; and
(3) the present value of an equity-based cash settled grant
under our long-term incentive plan, or LTIP. Under our
compensation structure, the allocation between base salary, STI
and LTIP varies depending upon job title and responsibility
levels. In 2008, this allocation for targeted compensation of
our executive officers was as follows:
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Targeted
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Targeted
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Base Salary
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STI Level
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LTIP Level
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CEO
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34
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%
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21
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%
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45
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%
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Chief Financial Officer, or CFO
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44
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%
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20
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%
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36
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%
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Vice Presidents
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44
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%
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20
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%
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36
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%
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In allocating compensation among these components, we believe a
significant portion of the compensation of our executive
officers should be performance-based since these individuals
have a greater opportunity to influence our performance. In
making this allocation, we have relied in part on the BDO study
of the companies named above. Each component of compensation is
further described below.
Base Salary Base salaries for
executives are determined based upon job responsibilities, level
of experience, individual performance, and comparisons to the
salaries of executives in similar positions obtained from the
BDO study. The goal of the base salary component is to
compensate executives at a level that approximates the median
salaries of individuals in comparable positions at comparably
sized companies in our industry.
The base salaries for executives are generally reevaluated
annually as part of our performance review process, or when
there is a change in the level of job responsibility. The base
salaries paid to our executive officers are set forth in the
Summary Compensation table below.
Annual Short-Term Cash Incentive, or
STI Under the STI, annual cash incentives
are provided to executives to promote the achievement of our
performance objectives. Target incentive opportunities for
executives under the STI are established as a percentage of base
salary. Incentive amounts are intended to provide total cash
compensation at the market median for executive officers in
comparable positions and
161
markets when target performance is achieved, below the market
median when performance is less than target and above the market
median when performance exceeds target. The BDO study was used
to determine the competitiveness of the incentive opportunity
for comparable positions. STI payments are generally paid in
cash in March of each year for the prior fiscal years
performance.
In 2008, the STI objectives were initially designed and proposed
by the executive officers and presented to the Chairman of the
General Partners board of directors. These objectives were
then considered and approved by the compensation committee and
ultimately by the full board of directors. In 2008, the STI
objectives approved by the compensation committee were divided
as follows: (1) company objectives accounted for 75% of the
STI and (2) personal objectives accounted for 25% of the
STI. The target incentive opportunities for 2008 as a percentage
of base salary for the CEO, the CFO, and the Vice Presidents
were 60%, 45% and 45%, respectively. All STI objectives are
subject to change each year.
The 2008 stated company objectives under the STI were based
on the following and were weighted as indicated:
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1)
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The achievement of our budget for operating cash flow from our
2008 budgeted asset base, excluding the impact from non-cash
mark to market adjustments to derivative instruments and any
one-time transaction costs. We define operating cash flow as our
distributable cash flow plus maintenance capital and interest
expense. As a publicly traded limited partnership, our
performance is generally judged on our ability to pay cash
distributions to our unitholders. Distributable cash flow has
three primary components: maintenance capital, interest expense
and operating cash flow. We use operating cash flow as the
financial objective because we believe it is the most
controllable component of distributable cash flow and permits
management to focus on the long term sustainability and
development of our assets. For this company objective, the
target level of performance is operating cash flow of
$118.0 million, the maximum level of performance is
operating cash flow of $135.0 million and the minimum level
of performance operating cash flow of $110.0 million. The
weighting of this objective relative to the other stated company
objectives was 35%.
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2)
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Deliver on board approved 2008 growth capital including
acquisitions, organic growth projects and the dropdown of assets
from our sponsors. We believe that our performance is also
judged by our growth, which can translate into distribution
growth. For this company objective, the target level of
performance is $400.0 million of approved growth capital in
2008, the maximum level of performance is $900.0 million of
approved growth capital in 2008 and the minimum level of
performance is $250.0 million of approved growth capital in
2008. The weighting of this objective relative to the other
stated company objectives was 25%.
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3)
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Establishing and maintaining strong internal controls and
accounting accuracy while meeting the performance requirements
of the Sarbanes-Oxley Act of 2002. For this company objective,
the minimum level of performance will be based on having no
material weaknesses identified by management or the external
auditor. A subjective determination will be made by the Audit
Committee to assess performance between the minimum and maximum
level of performance taking into consideration the number of
significant deficiencies identified. The weighting of this
objective relative to the other stated company objectives was 7%.
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4)
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A safety objective based on recordable incident rate, or RIR, of
both our assets and the assets of DCP Midstream, LLC, the owner
of our general partner and the operator or our assets. If a
fatality occurs of our employee or that of our contractor on our
premises, a 5% safety penalty will be assessed against the
entire STI payout. For this company objective, the target level
of performance is an RIR of 0.75, the maximum level of
performance is an RIR of 0.40 and the minimum level of
performance is an RIR of 0.95. The weighting of this objective
relative to the other stated company objectives was 5%.
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5)
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An environmental objective of non-routine air emissions, natural
gas vented or flared, of both our assets and the assets of DCP
Midstream, LLC. For this company objective, the target level of
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performance is 1,000 million standard cubic feet, or MMscf,
the maximum level of performance is 790 MMscf and the
minimum level of performance is 1,200 MMscf. The weighting
of this objective relative to the other stated company
objectives was 3%.
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The payout on these company objectives ranged from 0% if the
minimum level of performance was not achieved, 50% if the
minimum level of performance was achieved, 100% if the target
level of performance was achieved and 200% if the maximum level
of performance was achieved. When the performance level falls
between these percentages, payout will be determined by
straight-line interpolation. The level of performance achieved
for each objective was as follows:
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Level of
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STI Objective
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Performance Achieved
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1) Operating cash flow
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Between Minimum and Target
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2) Growth capital
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Between Minimum and Target
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3) Internal controls
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Target
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4) Safety
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Between Minimum and Target
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5) Environmental
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Below Minimum No Payout
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For fiscal year 2008, the compensation committee and the board
of directors adjusted the actual payout on the company
objectives downward to 50% of target. In making this adjustment,
we considered the current economic challenges created by the
U.S. and global recession, the performance of the
Partnerships publicly traded equity and the operational
challenges that were encountered by the Partnership in 2008.
Taking all of these factors into consideration, we felt that it
was prudent to reduce the annual cash incentives of management
for these company objectives. As a result of this adjustment,
the aggregate level of payout achieved for the above company
objectives will be 50% of target.
The 2008 stated personal objectives under the STI were
based on a number of individual performance objectives for each
employee, which included items such as distribution growth,
maintenance of strong liquidity in the debt and equity capital
markets, and execution of our growth strategies. The personal
objectives were approved by the compensation committee for the
CEO, and by the CEO for the other executive officers. The payout
on the individual personal objectives ranged from 0% if the
minimum level of performance was not achieved, 50% if the
minimum level of performance was achieved, 100% if the target
level of performance was achieved and 200% if the maximum level
of performance was achieved. When the performance level falls
between these percentages, payout will be determined by
straight-line interpolation.
For fiscal year 2008, the compensation committee and the board
of directors adjusted downward the actual payout on these
personal objectives as a result of the U.S. and global
recessions, the performance of the Partnerships publicly
traded equity and the operational challenges that were
encountered by the Partnership in 2008. As a result of these
adjustments, the aggregate level of payout achieved by the
executive officers as a group on their personal objectives will
be 54.5% of target.
As a result of the adjustments recommended by the compensation
committee and ratified by the board of directors discussed above
regarding the company objectives and the personal objectives,
the total payout for the executive officers under the STI for
fiscal year 2008 ranged from 37.5% to 65.5% of target, with the
CEO at 37.5%.
Long-Term Incentive Plan, or LTIP The
long-term incentive compensation program has the objective of
providing a focus on long-term value creation and enhancing
executive retention. Under our LTIP program, we issued phantom
limited partner units to each executive officer. Half of such
phantom units are performance phantom units, or PPUs, and half
are restricted phantom units, or RPUs. The PPUs will vest based
upon the level of achievement of certain performance objectives
over a three year performance period, or the Performance Period.
The RPUs will automatically vest if the executive officer
remains employed with us at the end of a three year vesting
period, or the Vesting Period. We believe this program promotes
retention of our executive officers, and focuses our executive
officers on the goal of long-term value creation.
For 2008, the PPUs have as a performance measurement total
shareholder return over the Performance Period relative to a
peer group of 31 other similar public limited partnerships that
we believe that we compete
163
with in the capital markets. The companies included in this peer
group at the start of 2008 were the following: Atlas Pipeline
Partners LP, Boardwalk Pipeline Partners LP, Buckeye Partners L
P, Copano Energy, L.L.C., Crosstex Energy LP, Duncan Energy
Partners L.P., Eagle Rock Energy Partners L P, El Paso
Pipeline Partners, L.P., Enbridge Energy Partners LP, Energy
Transfer Partners, L.P., Enterprise Products Partners L P,
Genesis Energy LP, Global Partners LP, Hiland Partners, LP,
Holly Energy Partners LP, Kinder Morgan Energy Partners LP,
Magellan Midstream Partners LP, MarkWest Energy Partners LP,
NuStar Energy L.P., ONEOK Partners LP, Plains All American
Pipeline LP, Quicksilver Gas Services LP, Regency Energy
Partners LP, Semgroup Energy Partners, L.P., Spectra Energy
Partners, LP, Sunoco Logistics Partners LP, Targa Resources
Partners LP, TC Pipelines LP, TEPPCO Partners LP, TransMontaigne
Partners L.P. and Williams Partners L.P. If a company originally
named to the peer group is not publicly traded at the end of the
Performance Period, none of its performance will be used in
calculating the peer groups total shareholder return. If
there is a combination of any peer group companies during the
Performance Period, the performance of the surviving entity will
be used. No new companies will be added to the peer group during
the Performance Period.
For 2008, the RPUs will vest automatically at the end of the
Vesting Period provided the executive officer remains employed
with us at the end of such period.
These PPU and RPU awards were granted at the first regular board
of directors meeting during the first quarter of 2008. The
number of awards granted to our executive officers is set forth
in the Grants of Plan-Based Awards table below.
Award recipients also received the right to receive dividend
equivalent rights, or DERs, on the number of units earned during
the Vesting Period. The DERs on the PPUs will be paid in cash at
the end of the Performance Period and the DERs on the RPUs will
be paid quarterly in cash during the Vesting Period. The amount
paid on the DERs will equal the quarterly distributions actually
paid during the Performance Period and the Vesting Period on the
number of PPUs or RPUs earned.
Our practice is to determine the dollar amount of long-term
incentive compensation that we want to provide, and to then
grant a number of PPUs and RPUs that have a fair market value
equal to that amount on the date of grant, which is based on the
closing price of our common units on the New York Stock Exchange
on the date of grant. Target long-term incentive opportunities
for executives under the plan are established as a percentage of
base salary, using the BDO study data for individuals in
comparable positions. The target 2008 long-term incentive
opportunities, expressed as a percentage of base salary, for the
CEO, the CFO and the Vice Presidents were 130%, 80% and 80%,
respectively.
For the PPUs granted in 2008, the performance measure is total
shareholder return over the Performance Period relative to the
peer group described above. This performance measure was
initially designed and proposed by the executive officers and
presented to the Chairman of the General Partners board of
directors. These objectives were then considered and approved by
the compensation committee and ultimately by the full board of
directors. The compensation committee believes utilizing total
shareholder return as a performance measure provides incentive
for the continued growth of our operating footprint and
distributions to unitholders. This performance measure, coupled
with the 2008 STI objectives to meet or exceed operating cash
flow targets, provides management with appropriate incentives
for our disciplined and steady growth. If our total shareholder
return ranking among the 31 companies listed in our peer
group over the Performance Period is less than the
30th percentile, 0% of the PPUs will vest. If such ranking
over the Performance Period is in the 30th percentile, 50%
percent of the PPUs will vest. If such ranking over the
Performance Period is in the 50th percentile, 100% of the
PPUs will vest and if such ranking over the Performance Period
is in the 90th percentile, 200% of the PPUs will vest.
Total shareholder return will be based on data obtained from
Bloomberg and assumes that any dividends or distributions are
reinvested.
In the event that any person other than DCP Midstream, LLC
and/or an
affiliate thereof becomes the beneficial owner of more than 50%
of the combined voting power of the General Partners
equity interests prior to the completion of the Performance
Period, the PPUs, RPUs and related DERs will (i) be
replaced with equivalent units of the new enterprise if there is
no change in the recipients job status for twelve months
or (ii) fully vest if the recipient is severed or if the
recipients job is lower in status within twelve months of
the change in control.
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In the event an award recipients employment is terminated
after the first anniversary of the grant date for reasons of
death, disability, early or normal retirement, or if the
recipient is terminated by the General Partner for reasons other
than cause, the recipients (i) performance units will
contingently vest on a pro-rata basis for time worked over the
Performance Period and final performance, measured at the end of
the Performance Period, will determine the payout and
(ii) time vested units will become fully vested and
payable. Termination of employment for any other reason will
result in the forfeiture of any unvested units.
Other Compensation In addition, our
executives are eligible to participate in other compensation
programs, which include but are not limited to:
Phantom IPO Units In conjunction with our
initial public offering, in January 2006 our General
Partners board of directors granted phantom limited
partnership units, or Phantom IPO Units, to key employees,
including the executive officers. These Phantom IPO Units vested
in January 2009 and were paid in common units. There was no
performance condition associated with these Phantom IPO Units.
Award recipients also received DERs based on the number of
common units awarded, which were paid in cash on a quarterly
basis from the date of the initial grant. These phantom IPO
units were granted to reward those key employees and executive
officers that made significant contributions to our successful
initial public offering. The amounts of awards granted to our
executive officers are set forth in the Grants of
Plan-Based Awards table below.
Company Matching and Retirement Contributions to Defined
Contribution Plans Employees may elect to
participate in the DCP Midstream, LP 401(k) and Retirement Plan.
Under the plan, employees may elect to defer up to 75% of their
eligible compensation, or up to the limits specified by the
Internal Revenue Service. We match the first 6% of eligible
compensation contributed by the employee to the plan. In
addition, we make retirement contributions ranging from 4% to 7%
of the eligible compensation of qualifying participants to the
plan, based on years of service, up to the limits specified by
the Internal Revenue Service. We have no defined benefit plans.
Miscellaneous Compensation Our executive
officers are eligible to participate in a nonqualified deferred
compensation program. Executive officers are allowed to defer up
to 75% of their base salary, and up to 100% of their STI, LTIP
or other compensation. Executive officers elect either to
receive amounts contributed during specific plan years as a lump
sum at a specific date, subject to Internal Revenue Service
rules, or in a lump sum or annual annuity (over three to
20 years) at termination.
Executive officers and other eligible employees may participate
in a nonqualified, defined contribution retirement plan.
Benefits earned under this plan are attributable to compensation
in excess of the annual compensation limits under
section 401(k) of the Internal Revenue Code. Under this
plan, we make a contribution of up to 13% of eligible
compensation, as defined by this plan, to the nonqualified
deferred compensation program.
In addition, we provide our employees, including the executive
officers, with a variety of health and welfare benefit programs.
The health and welfare programs are intended to protect
employees against catastrophic loss and promote well being.
These programs include medical, wellness, pharmacy, dental, life
insurance premiums, and accidental death and disability. In
addition, we pay certain perquisites to our executives, which
include items such as financial planning, club dues and an
allowance towards annual physical exam expenses. Finally, we
provide all our employees with a monthly parking pass or a pass
to be used on available public transportation systems.
We are a partnership and not a corporation for U.S. federal
income tax purposes, and therefore, are not subject to the
executive compensation tax deductible limitations of Internal
Revenue Code § 162(m). Accordingly, none of the
compensation paid to our named executive officers is subject to
the limitation.
Other
Unit Ownership Guidelines To underscore the
importance of linking executive and unitholder interests, the
board of directors of our General Partner has adopted unit
ownership guidelines for executive officers and key employees
who are eligible to receive long-term incentive awards. To that
extent, the board has established target equity ownership
obligations for the various levels of executives, which have a
five-year build term from
165
the date the executive officer commences employment with us.
Ownership is reported annually to the compensation committee. As
of December 31, 2008, the unit ownership guidelines for the
executive officers were as follows:
|
|
|
|
|
|
|
Number of
|
|
|
|
Units
|
|
|
CEO
|
|
|
28,000
|
|
CFO
|
|
|
10,000
|
|
Vice Presidents
|
|
|
10,000
|
|
Report of
the Compensation Committee
The compensation committee has reviewed and discussed with
management the Compensation Discussion and Analysis
presented above. Members of management with whom the
compensation committee had discussions are the Chief Executive
Officer of the General Partner and the Group Vice President and
Chief Administrative Officer of DCP Midstream, LLC. In addition,
the compensation committee engaged the services of BDO Seidman,
LLP, and a compensation consultant, to conduct a study to assist
us in establishing overall compensation packages for our
executives. Based on this review and discussion, we recommended
to the board of directors of the General Partner that the
Compensation Discussion and Analysis referred to
above be included in this annual report on
Form 10-K
for the year ended December 31, 2008.
Compensation Committee
Alan N. Harris (Chairman)
Gregory J. Goff
Frank A. McPherson
Thomas C. OConnor
Executive
Compensation
The following table discloses the compensation of the General
Partners principal executive officers, principal financial
officer and named executive officers, or collectively, the
executive officers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonqualified
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Equity
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive Plan
|
|
Compensation
|
|
All Other
|
|
|
Name and Principal Position
|
|
Year
|
|
Salary
|
|
LTIP Awards(e)
|
|
Compensation
|
|
Earnings(f)
|
|
Compensation(g)
|
|
Total
|
|
Mark A. Borer(a)
|
|
|
2008
|
|
|
$
|
358,538
|
|
|
$
|
(34,138
|
)
|
|
$
|
80,671
|
|
|
$
|
56,236
|
|
|
$
|
126,851
|
|
|
$
|
588,158
|
|
President and Chief
|
|
|
2007
|
|
|
$
|
341,000
|
|
|
$
|
151,763
|
|
|
$
|
331,043
|
|
|
$
|
36,518
|
|
|
$
|
80,908
|
|
|
$
|
941,232
|
|
Executive Officer
|
|
|
2006
|
|
|
$
|
47,215
|
|
|
$
|
|
|
|
$
|
46,655
|
|
|
$
|
45
|
|
|
$
|
2,052
|
|
|
$
|
95,967
|
|
Angela A. Minas(b)
|
|
|
2008
|
|
|
$
|
61,923
|
|
|
$
|
3,541
|
|
|
$
|
18,252
|
|
|
$
|
|
|
|
$
|
49,199
|
|
|
$
|
132,915
|
|
Vice President and Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas E. Long(c)
|
|
|
2008
|
|
|
$
|
76,168
|
|
|
$
|
(396,593
|
)
|
|
$
|
|
|
|
$
|
(61,564
|
)
|
|
$
|
31,955
|
|
|
$
|
(350,034
|
)
|
Vice President and
|
|
|
2007
|
|
|
$
|
199,212
|
|
|
$
|
304,402
|
|
|
$
|
145,605
|
|
|
$
|
1,584
|
|
|
$
|
54,268
|
|
|
$
|
705,071
|
|
Chief Financial Officer
|
|
|
2006
|
|
|
$
|
180,000
|
|
|
$
|
92,191
|
|
|
$
|
133,650
|
|
|
$
|
|
|
|
$
|
33,182
|
|
|
$
|
439,023
|
|
Michael S. Richards
|
|
|
2008
|
|
|
$
|
181,748
|
|
|
$
|
(232,166
|
)
|
|
$
|
52,343
|
|
|
$
|
(6,765
|
)
|
|
$
|
65,136
|
|
|
$
|
60,296
|
|
Vice President, General
|
|
|
2007
|
|
|
$
|
172,615
|
|
|
$
|
282,729
|
|
|
$
|
125,903
|
|
|
$
|
48
|
|
|
$
|
46,431
|
|
|
$
|
627,726
|
|
Counsel and Secretary
|
|
|
2006
|
|
|
$
|
165,000
|
|
|
$
|
88,390
|
|
|
$
|
122,048
|
|
|
$
|
|
|
|
$
|
32,717
|
|
|
$
|
408,155
|
|
Greg K. Smith(d)
|
|
|
2008
|
|
|
$
|
190,970
|
|
|
$
|
(236,289
|
)
|
|
$
|
32,226
|
|
|
$
|
(4,248
|
)
|
|
$
|
69,620
|
|
|
$
|
52,279
|
|
Vice President, Business
|
|
|
2007
|
|
|
$
|
179,644
|
|
|
$
|
289,184
|
|
|
$
|
131,080
|
|
|
$
|
866
|
|
|
$
|
51,185
|
|
|
$
|
651,959
|
|
Development
|
|
|
2006
|
|
|
$
|
170,000
|
|
|
$
|
89,600
|
|
|
$
|
121,444
|
|
|
$
|
480
|
|
|
$
|
36,044
|
|
|
$
|
417,568
|
|
|
|
|
(a) |
|
Mr. Borers employment with the General Partner
commenced effective November 10, 2006. |
166
|
|
|
(b) |
|
Ms. Minas employment with the General Partner
commenced effective September 8, 2008. |
|
(c) |
|
Mr. Longs employment with the General Partner
terminated effective April 30, 2008. |
|
(d) |
|
Mr. Smiths employment with the General Partner
terminated effective January 5, 2009, and he commenced
employment with DCP Midstream, LLC. Mr. Smith has been
replaced by Don Baldridge, formerly employed by DCP Midstream,
LLC. |
|
(e) |
|
The amounts in this column reflect the dollar amount recognized
for financial statement reporting purposes in accordance with
the provisions of Statement of Financial Accounting Standard
No. 123(R), Share-Based Payment, or SFAS 123R, which
incorporates re-measurement of awards for changes in the
underlying assumptions used in prior periods, such as the unit
price at the measurement date and the performance measure
percentage. These amounts reflect our accounting expense and may
not necessarily correspond to the actual value that will be
realized by the named executives. The amounts exclude the impact
of an estimated forfeiture rate under SFAS 123R, but do
include the impact of forfeited awards if any of the named
executives fail to perform the requisite service. Accordingly,
the amounts may be negative due to these factors. This column
reflects awards granted in January 2006 related to our
initial public offering, and awards granted in conjunction with
our LTIP. See Note 14 of the Notes to Consolidated
Financial Statements in Item 8, Financial Statements
and Supplementary Data. |
|
(f) |
|
Amounts in this column are also included in the
Nonqualified Deferred Compensation table below. |
|
(g) |
|
Includes DERs, company retirement and nonqualified deferred
compensation program contributions by the Partnership, the value
of life insurance premiums paid by the Partnership on behalf of
an executive and other deminimus compensation. |
Mark
A. Borer, President and CEO
The annual base salary for Mr. Borer was $365,000 for 2008
and $341,000 for both 2007 and 2006, of which he deferred
$125,488, $120,391 and $8,944 in 2008, 2007 and 2006,
respectively. The LTIP awards are comprised of PPUs and RPUs
pursuant to the LTIP. Under the 2008, 2007 and 2006 STI,
Mr. Borers target opportunity was 60% of his annual
base salary, with the possibility of earning from 0 to 120% of
his annual base salary in 2008, and 0% to 109% of his annual
base salary in 2007 and 2006, depending on the level of
performance in each of the STI objectives, which was pro rated
in 2006 based upon his service period during 2006. While an
employee at DCP Midstream, LLC during 2006, he received various
equity grants and other compensation which are not reflected as
part of the compensation attributable to his service with the
Partnership.
All Other Compensation includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Company retirement contributions to defined contribution plans
|
|
$
|
29,900
|
|
|
$
|
29,950
|
|
|
$
|
|
|
Nonqualified deferred compensation program contributions
|
|
$
|
50,160
|
|
|
$
|
32,063
|
|
|
$
|
1,945
|
|
DERs
|
|
$
|
44,947
|
|
|
$
|
18,370
|
|
|
$
|
|
|
Life insurance premiums(a)
|
|
$
|
1,844
|
|
|
$
|
1,225
|
|
|
$
|
107
|
|
|
|
|
(a) |
|
Paid by the Partnership on behalf of Mr. Borer. |
Angela
A. Minas, Vice President and CFO
The annual base salary for Ms. Minas was $230,000 for 2008,
of which she deferred $0 in 2008. The LTIP awards are comprised
of PPUs and RPUs pursuant to the LTIP. Under the 2008 STI,
Ms. Minas target opportunity was 45% of her annual
base salary, with the possibility of earning from 0% to 90% of
her annual base salary, depending on the level of performance in
each of the STI objectives, which was pro rated in 2008 based
upon her service period in 2008.
167
All Other Compensation includes the following:
|
|
|
|
|
|
|
2008
|
|
|
Relocation expenses
|
|
$
|
41,901
|
|
Company retirement contributions to defined contribution plans
|
|
$
|
5,131
|
|
DERs
|
|
$
|
2,034
|
|
Life insurance premiums(a)
|
|
$
|
133
|
|
|
|
|
(a) |
|
Paid by the Partnership on behalf of Ms. Minas. |
Thomas
E. Long, former Vice President and CFO
The annual base salary for Mr. Long was $215,000, $199,980
and $180,000 for 2008, 2007 and 2006, respectively, of which he
deferred $131,070, $89,645 and $0 in 2008, 2007 and 2006,
respectively. The LTIP awards are comprised of Phantom IPO
Units, PPUs and RPUs pursuant to the LTIP. Under the 2008, 2007
and 2006 STI, Mr. Longs target opportunity was 45% of
his annual base salary, with the possibility of earning from 0%
to 90% of his annual base salary in 2008, and 0% to 82% of his
annual base salary in 2007 and 2006, depending on the level of
performance in each of the STI objectives.
All Other Compensation includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Company retirement contributions to defined contribution plans
|
|
$
|
11,795
|
|
|
$
|
28,476
|
|
|
$
|
21,553
|
|
Nonqualified deferred compensation program contributions
|
|
$
|
14,796
|
|
|
$
|
|
|
|
$
|
|
|
DERs
|
|
$
|
5,324
|
|
|
$
|
25,075
|
|
|
$
|
10,981
|
|
Life insurance premiums(a)
|
|
$
|
40
|
|
|
$
|
717
|
|
|
$
|
648
|
|
|
|
|
(a) |
|
Paid by the Partnership on behalf of Mr. Long. |
Michael
S. Richards, Vice President, General Counsel and
Secretary
The annual base salary for Mr. Richards was $185,000,
$172,920 and $165,000 for 2008, 2007 and 2006, respectively, of
which he deferred $15,397, $3,452 and $0 in 2008, 2007 and 2006,
respectively. The LTIP awards are comprised of Phantom IPO
Units, PPUs and RPUs pursuant to the LTIP. Under both the 2008
and 2007 STI, Mr. Richards target opportunity was 45%
of his annual base salary, with the possibility of earning from
0% to 90% of his annual base salary in 2008, and 0% to 82% of
his annual base salary in 2007 and 2006, depending on the level
of performance in each of the STI objectives.
All Other Compensation includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Company retirement contributions to defined contribution plans
|
|
$
|
23,000
|
|
|
$
|
22,500
|
|
|
$
|
20,891
|
|
Nonqualified deferred compensation program contributions
|
|
$
|
6,550
|
|
|
$
|
|
|
|
$
|
|
|
DERs
|
|
$
|
35,020
|
|
|
$
|
23,309
|
|
|
$
|
10,482
|
|
Life insurance premiums(a)
|
|
$
|
566
|
|
|
$
|
622
|
|
|
$
|
594
|
|
Deminimus bonus
|
|
$
|
|
|
|
$
|
|
|
|
$
|
750
|
|
|
|
|
(a) |
|
Paid by the Partnership on behalf of Mr. Richards. |
Greg
K. Smith, former Vice President, Business
Development
The annual base salary for Mr. Smith was $195,000, $180,030
and $170,000 for 2008, 2007 and 2006, respectively, of which he
deferred $7,638, $7,186 and $6,800 in 2008, 2007 and 2006,
respectively. The LTIP awards are comprised of Phantom IPO
Units, PPUs and RPUs pursuant to the LTIP. Under the 2008, 2007
and 2006 STI, Mr. Smiths target opportunity was 45%
of his annual base salary, with the possibility of earning
168
from 0% to 90% of his annual base salary in 2008, and 0% to 82%
of his annual base salary in 2007 and 2006, depending on the
level of performance in each of the STI objectives.
All Other Compensation includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Company retirement contributions to defined contribution plans
|
|
$
|
23,926
|
|
|
$
|
23,855
|
|
|
$
|
21,928
|
|
Nonqualified deferred compensation program contributions
|
|
$
|
9,265
|
|
|
$
|
2,864
|
|
|
$
|
2,864
|
|
DERs
|
|
$
|
36,030
|
|
|
$
|
23,818
|
|
|
$
|
10,640
|
|
Life insurance premiums(a)
|
|
$
|
399
|
|
|
$
|
648
|
|
|
$
|
612
|
|
|
|
|
(a) |
|
Paid by the Partnership on behalf of Mr. Smith. |
Grants of
Plan-Based Awards
Following are the grants of plan-based awards during the year
ended December 31, 2008 for the General Partners
executive officers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
Estimated Future Payouts under Non-Equity Incentive Plan
Awards (a)
|
|
|
Estimated Future Payouts under Equity Incentive Plan
Awards
|
|
|
of LTIP
|
|
|
|
|
|
Minimum
|
|
|
Target
|
|
|
Maximum
|
|
|
Minimum
|
|
|
Target
|
|
|
Maximum
|
|
|
Awards
|
|
Name
|
|
Grant Date
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
(#)
|
|
|
(#)
|
|
|
(#)
|
|
|
($)
|
|
|
Mark A. Borer
|
|
NA
|
|
$
|
109,500
|
|
|
$
|
219,000
|
|
|
$
|
438,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
PPUs
|
|
2/25/2008(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
3,305
|
|
|
|
6,610
|
|
|
|
9,915
|
|
|
$
|
237,167
|
|
RPUs
|
|
2/25/2008(c)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
6,610
|
|
|
|
6,610
|
|
|
|
6,610
|
|
|
$
|
237,167
|
|
Angela A. Minas
|
|
NA
|
|
$
|
51,750
|
|
|
$
|
103,500
|
|
|
$
|
207,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
PPUs
|
|
2/25/2008(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
848
|
|
|
|
1,695
|
|
|
|
2,543
|
|
|
$
|
28,273
|
|
RPUs
|
|
2/25/2008(c)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
1,695
|
|
|
|
1,695
|
|
|
|
1,695
|
|
|
$
|
28,273
|
|
Michael S. Richards
|
|
NA
|
|
$
|
41,625
|
|
|
$
|
83,250
|
|
|
$
|
166,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
PPUs
|
|
2/25/2008(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
1,030
|
|
|
|
2,060
|
|
|
|
3,090
|
|
|
$
|
73,913
|
|
RPUs
|
|
2/25/2008(c)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
2,060
|
|
|
|
2,060
|
|
|
|
2,060
|
|
|
$
|
73,913
|
|
Greg K. Smith
|
|
NA
|
|
$
|
43,875
|
|
|
$
|
87,750
|
|
|
$
|
175,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
PPUs
|
|
2/25/2008(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
1,088
|
|
|
|
2,175
|
|
|
|
3,263
|
|
|
$
|
78,039
|
|
RPUs
|
|
2/25/2008(c)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
2,175
|
|
|
|
2,175
|
|
|
|
2,175
|
|
|
$
|
78,039
|
|
|
|
|
(a) |
|
Amounts shown represent amounts under the STI. If minimum levels
of performance are not met, then the payout for one or more of
the components of the STI may be zero. |
|
(b) |
|
The number of units shown represents units awarded under the
LTIP. If minimum levels of performance are not met, then the
payout may be zero. |
|
(c) |
|
The number of units shown represents units awarded under the
LTIP and these units vest at the end of the Vesting Period
provided the individual is still employed by the Partnership. |
The PPUs awarded on February 25, 2008 will vest in their
entirety on December 31, 2010 if the specified performance
conditions are satisfied and the RPUs awarded on
February 25, 2008 will vest in their entirety on
December 31, 2010 if the executive is still employed by the
Partnership.
169
Outstanding
Equity Awards at Fiscal Year-End
Following are the outstanding equity awards for the General
Partners executive officers as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding LTIP Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Incentive
|
|
|
|
|
|
|
|
|
|
Equity Incentive
|
|
|
Plan Awards:
|
|
|
|
|
|
|
|
|
|
Plan Awards:
|
|
|
Market Value of
|
|
|
|
|
|
|
Market Value of
|
|
|
Unearned Units
|
|
|
Unearned Units
|
|
|
|
Units That Have
|
|
|
Units That Have Not
|
|
|
That Have Not
|
|
|
That Have Not
|
|
Name
|
|
Not Vested(a)
|
|
|
Vested(b)
|
|
|
Vested(c)
|
|
|
Vested(b)
|
|
|
Mark A. Borer
|
|
|
|
|
|
$
|
|
|
|
|
25,110
|
|
|
$
|
238,269
|
|
Angela A. Minas
|
|
|
|
|
|
$
|
|
|
|
|
3,390
|
|
|
$
|
31,866
|
|
Michael S. Richards
|
|
|
4,000
|
|
|
$
|
37,600
|
|
|
|
12,730
|
|
|
$
|
138,968
|
|
Greg K. Smith
|
|
|
4,000
|
|
|
$
|
37,600
|
|
|
|
13,250
|
|
|
$
|
144,416
|
|
|
|
|
(a) |
|
Phantom IPO Units awarded 1/3/2006; units vest in their entirety
on 1/3/2009. For additional information, see Compensation
Discussion and Analysis Other
Compensation Phantom IPO Units. |
|
(b) |
|
Value calculated based on the closing price of our common units
at December 31, 2008. |
|
(c) |
|
PPUs and RPUs awarded 5/5/2006, 2/26/2007 and 2/25/2008; units
vest in their entirety over a range of 0% to 150% on 12/31/2008,
12/31/2009 and 12/31/2010, respectively, if the specified
performance conditions are satisfied, except that the RPUs vest
in their entirety on 12/31/2010; to determine the market value,
the calculation of the number of units that are expected to vest
for units granted in 2008 is based on assumed performance at
100%, for units granted in 2007 is based on assumed performance
at 102%, and for units granted in 2006 is based on actual
performance at 140.4%. |
Options
Exercises and Stock Vested
There were no options exercised and no limited partnership units
held by our executive officers that vested during the year ended
December 31, 2008.
Nonqualified
Deferred Compensation
Following is the nonqualified deferred compensation for the
General Partners executive officers for the year ended
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executive
|
|
|
Registrant
|
|
|
Aggregate Earnings
|
|
|
|
|
|
Aggregate
|
|
|
|
Contributions in
|
|
|
Contributions in
|
|
|
(Losses) in
|
|
|
Aggregate
|
|
|
Balance at
|
|
|
|
Last Fiscal
|
|
|
Last Fiscal
|
|
|
Last Fiscal
|
|
|
Withdrawals/
|
|
|
December 31,
|
|
Name
|
|
Year(a)
|
|
|
Year(b)
|
|
|
Year(c)
|
|
|
Distributions
|
|
|
2008
|
|
|
Mark A. Borer
|
|
$
|
125,488
|
|
|
$
|
50,160
|
|
|
$
|
56,236
|
|
|
$
|
|
|
|
$
|
901,245
|
|
Thomas E. Long
|
|
$
|
131,070
|
|
|
$
|
14,796
|
|
|
$
|
(61,564
|
)
|
|
$
|
(27,339
|
)
|
|
$
|
148,337
|
|
Angela A. Minas
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Michael S. Richards
|
|
$
|
15,397
|
|
|
$
|
6,550
|
|
|
$
|
(6,765
|
)
|
|
$
|
|
|
|
$
|
18,708
|
|
Greg K. Smith
|
|
$
|
7,638
|
|
|
$
|
9,265
|
|
|
$
|
(4,248
|
)
|
|
$
|
|
|
|
$
|
44,305
|
|
|
|
|
(a) |
|
These amounts were included in the gross salary reported in the
Salary column of the Summary
Compensation table. |
|
(b) |
|
These amounts are included in the Summary
Compensation table within All Other
Compensation. |
|
(c) |
|
These amounts are included in the Summary
Compensation table as Change in Nonqualified
Deferred Compensation Earnings. |
Potential
Payments Upon Termination or Change in Control
As noted above, the General Partner has not entered into any
employment agreements with any of our executive officers. There
are no formal severance plans in place for any employees in the
event of termination
170
of employment, or a change in control of the Partnership. When
an employee terminates employment with the Partnership, they are
entitled to a cash payment for the amount of unused vacation
hours at the date of their termination.
Compensation
of Directors
General Effective February 17, 2009, the
board of directors of the General Partner approved a
compensation package for directors who are not officers or
employees of affiliates of the General Partner, or Non-Employee
Directors. Members of the board who are also officers or
employees of affiliates of the General Partner do not receive
additional compensation for serving on the board. The board
approved the payment to each Non-Employee Director of an annual
compensation package containing the following: (1) a
$40,000 retainer; (2) a board meeting fee of $1,250 for
each board meeting attended; (3) a telephonic board meeting
fee of $500 for each telephonic meeting attended; and
(4) an annual grant of Phantom Units that approximate
$40,000 of value, awarded pursuant to the LTIP, that have a six
month vesting period. The directors also receive DERs, based on
the number of units awarded, which are paid in cash on a
quarterly basis. The Phantom Units will be paid in units upon
vesting.
Our directors will also be reimbursed for out-of-pocket expenses
in connection with attending meetings of the board of directors
and committees. Each director will be fully indemnified by us
for his actions associated with being a director to the fullest
extent permitted under Delaware law.
Committees The chairman of the audit
committee of the board will receive an annual retainer of
$20,000 and the members of the audit committee will receive
$1,500 for each audit committee meeting attended. The chairman
of the special committee of the board will likewise receive an
annual retainer of $20,000 and the members of the special
committee will receive $1,250 for each special committee meeting
attended. Finally, the Non-Employee Director members of the
compensation committee will receive $1,250 for each compensation
committee meeting attended.
Following is the compensation of the General Partners
Non-Employee Directors for the year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LTIP
|
|
|
|
|
|
|
|
Name
|
|
Fees Earned
|
|
|
Awards(a)
|
|
|
DERs
|
|
|
Total
|
|
|
Paul F. Ferguson, Jr.
|
|
$
|
90,000
|
|
|
$
|
5,479
|
|
|
$
|
2,762
|
|
|
$
|
98,241
|
|
Frank A. McPherson
|
|
$
|
72,500
|
|
|
$
|
5,479
|
|
|
$
|
2,762
|
|
|
$
|
80,741
|
|
Thomas C. Morris
|
|
$
|
69,000
|
|
|
$
|
5,479
|
|
|
$
|
2,762
|
|
|
$
|
77,241
|
|
Stephen R. Springer
|
|
$
|
89,500
|
|
|
$
|
24,774
|
|
|
$
|
1,475
|
|
|
$
|
115,749
|
|
|
|
|
(a) |
|
The amounts in this column reflect the dollar amount recognized
for financial statement reporting purposes, in accordance with
the provisions of SFAS 123R, and include amounts from
awards granted in conjunction with our LTIP. See Note 14 of
the Notes to Consolidated Financial Statements in Item 8.
Financial Statements and Supplementary Data. |
Mr. Ferguson is the audit committee chair and a member of
the special committee.
Mr. McPherson was the special committee chair until
February 2008, and is a member of the audit committee and the
compensation committee.
Mr. Morris is a member of the audit committee and the
special committee.
Mr. Springer is the special committee chair, and is a
member of the audit committee.
The total aggregate grant date fair value of LTIP awards for the
Non-Employee Directors for 2008 was $143,520. At
December 31, 2008, Messrs. Ferguson, McPherson and
Morris each had 666 Phantom IPO Units outstanding, which vested
on January 3, 2009 and were paid in common units.
171
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Unitholder Matters
|
The following table sets forth the beneficial ownership of our
units and the related transactions held by:
|
|
|
|
|
each person who beneficially owns 5% or more of our outstanding
units as of February 23, 2009;
|
|
|
|
all of the directors of DCP Midstream GP, LLC;
|
|
|
|
each Named Executive Officer of DCP Midstream GP, LLC; and
|
|
|
|
all directors and executive officers of DCP Midstream GP, LLC as
a group.
|
Percentage of total common units beneficially owned is based on
28,233,183 common units outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
Common
|
|
|
Common
|
|
|
|
Units
|
|
|
Units
|
|
|
|
Beneficially
|
|
|
Beneficially
|
|
Name of Beneficial Owner(a)
|
|
Owned
|
|
|
Owned
|
|
|
DCP LP Holdings, LP(b)(1)
|
|
|
8,246,451
|
|
|
|
29.2
|
%
|
Kayne Anderson Capital Advisors, L.P.(c)
|
|
|
1,778,335
|
|
|
|
6.3
|
%
|
Barclays PLC(d)
|
|
|
1,666,334
|
|
|
|
5.9
|
%
|
Mark A. Borer
|
|
|
38,001
|
|
|
|
|
*
|
Angela A. Minas
|
|
|
15,000
|
|
|
|
|
*
|
Michael S. Richards
|
|
|
12,101
|
|
|
|
|
*
|
Don Baldridge
|
|
|
6,101
|
|
|
|
|
*
|
Alan N. Harris
|
|
|
9,842
|
|
|
|
|
*
|
Paul F. Ferguson, Jr.
|
|
|
6,334
|
|
|
|
|
*
|
John E. Lowe
|
|
|
40,001
|
|
|
|
|
*
|
Frank A. McPherson
|
|
|
15,666
|
|
|
|
|
*
|
Thomas C. Morris
|
|
|
20,667
|
|
|
|
|
*
|
Thomas C. OConnor
|
|
|
8,000
|
|
|
|
|
*
|
Stephen R. Springer
|
|
|
1,500
|
|
|
|
|
*
|
All directors and executive officers as a group (11 persons)
|
|
|
173,213
|
|
|
|
|
*
|
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
Unless otherwise indicated, the address for all beneficial
owners in this table is 370 17th Street, Suite 2775,
Denver, Colorado 80202. |
|
(b) |
|
DCP Midstream, LLC is the ultimate parent company of DCP LP
Holdings, LP and may, therefore, be deemed to beneficially own
the units held by DCP LP Holdings, LP. DCP Midstream, LLC
disclaims beneficial ownership of all of the units owned by DCP
LP Holdings, LP. The address of DCP LP Holdings, LP and DCP
Midstream, LLC is 370 17th Street, Suite 2500, Denver,
Colorado 80202. |
|
(c) |
|
As set forth in a Schedule 13G filed on February 17,
2009. The address of Kayne Anderson Capital Advisors, L.P. is
1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067. |
|
(d) |
|
As set forth in a Schedule 13G filed on September 22,
2008. The address of Barclays PLC is 1 Churchill Place, London,
E14 5HP, England. |
172
Equity
Compensation Plan Information
The following table summarizes information about our equity
compensation plan as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Number of Securities
|
|
|
|
Securities to be
|
|
|
|
|
|
Remaining Available for
|
|
|
|
Issued upon
|
|
|
Weighted-Average
|
|
|
Future Issuance Under
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
Equity Compensation
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Plans (Excluding
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Securities Reflected in
|
|
|
|
and rights (1)
|
|
|
and Rights
|
|
|
Column (a))
|
|
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans approved by unitholders
|
|
|
|
|
|
$
|
|
|
|
|
|
|
Equity compensation plans not approved by unitholders
|
|
|
|
|
|
|
|
|
|
|
769,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
|
|
|
|
769,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The long-term incentive plan currently permits the grant of
awards covering an aggregate of 850,000 units. For more
information on our long-term incentive plan, which did not
require approval by our limited partners, refer to Item 11.
Executive Compensation Components of
Compensation. |
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Distributions
and Payments to our General Partner and its Affiliates
The following table summarizes the distributions and payments to
be made by us to our General Partner and its affiliates in
connection with our formation, ongoing operation, and
liquidation. These distributions and payments are determined by
and among affiliated entities and, consequently, are not the
result of arms-length negations.
|
|
|
|
Operational Stage:
|
|
|
|
Distributions of Available Cash to our General Partner and its
affiliates
|
|
|
We will generally make cash distributions to the unitholders and
to our General Partner, in accordance with their pro rata
interest. In addition, if distributions exceed the minimum
quarterly distribution and other higher target levels, our
General Partner will be entitled to increasing percentages of
the distributions, up to 48% of the distributions above the
highest target level. Currently, our distribution to our general
partner related to its incentive distribution rights is at the
highest level.
|
Payments to our General Partner and its affiliates
|
|
|
We reimburse DCP Midstream, LLC and its affiliates $10.1 million
per year, adjusted annually by changes in the Consumer Price
Index, for the provision of various general and administrative
services for our benefit. For further information regarding the
reimbursement, please see the Omnibus Agreement
section below.
|
Withdrawal or removal of our General Partner
|
|
|
If our General Partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests.
|
Liquidation Stage:
|
|
|
|
Liquidation
|
|
|
Upon our liquidation, the partners, including our General
Partner, will be entitled to receive liquidating distributions
according to their respective capital account balances.
|
|
|
|
|
173
Omnibus
Agreement
The employees supporting our operations are employees of DCP
Midstream, LLC. We have entered into an omnibus agreement, as
amended, or the Omnibus Agreement, with DCP Midstream, LLC.
Under the Omnibus Agreement, we are required to reimburse DCP
Midstream, LLC for salaries of operating personnel and employee
benefits as well as capital expenditures, maintenance and repair
costs, taxes and other direct costs incurred by DCP Midstream,
LLC on our behalf. The fees under the Omnibus Agreement
increased $0.4 million per year effective October 1,
2008, in connection with the acquisition of Michigan
Pipeline & Processing, LLC, or MPP. We also pay DCP
Midstream, LLC an annual fee for centralized corporate functions
performed by DCP Midstream, LLC on our behalf, including legal,
accounting, cash management, insurance administration and claims
processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll, taxes
and engineering.
Following is a summary of the fees we anticipate incurring in
2009 under the Omnibus Agreement and the effective date for
these fees:
|
|
|
|
|
|
|
Terms
|
|
Effective Date
|
|
Fee
|
|
|
|
|
|
(Millions)
|
|
|
Annual fee
|
|
2006
|
|
$
|
5.1
|
|
Wholesale propane logistics business
|
|
November 2006
|
|
|
2.0
|
|
Southern Oklahoma
|
|
May 2007
|
|
|
0.2
|
|
Discovery
|
|
July 2007
|
|
|
0.2
|
|
Additional services
|
|
August 2007
|
|
|
0.6
|
|
Momentum Energy Group, Inc.
|
|
August 2007
|
|
|
1.6
|
|
Michigan Pipeline & Processing, LLC
|
|
October 2008
|
|
|
0.4
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
10.1
|
|
|
|
|
|
|
|
|
All of the fees under the Omnibus Agreement are subject to
adjustment annually for changes in the Consumer Price Index.
The Omnibus Agreement also addresses the following matters:
|
|
|
|
|
DCP Midstream, LLCs obligation to indemnify us for certain
liabilities and our obligation to indemnify DCP Midstream, LLC
for certain liabilities;
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support, including without limitation guarantees and
letters of credit, for our obligations related to derivative
financial instruments, such as commodity price derivative
contracts, to the extent that such credit support arrangements
were in effect as of December 7, 2005 until the earlier of
December 7, 2010 or when we obtain an investment grade
credit rating from either Moodys Investor Services, Inc.
or Standard & Poors Ratings Group with respect
to any of our unsecured indebtedness; and
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its
credit support, including without limitation guarantees and
letters of credit, for our obligations related to commercial
contracts with respect to its business or operations that were
in effect at the closing of our initial public offering until
the expiration of such contracts.
|
Our General Partner and its affiliates will also receive
payments from us pursuant to the contractual arrangements
described below under the caption Contracts with
Affiliates.
Any or all of the provisions of the Omnibus Agreement, other
than the indemnification provisions described below, will be
terminable by DCP Midstream, LLC at its option if our general
partner is removed without cause and units held by our general
partner and its affiliates are not voted in favor of that
removal. The Omnibus Agreement will also terminate in the event
of a change of control of us, our general partner (DCP Midstream
GP, LP) or our General Partner (DCP Midstream GP, LLC).
174
Competition
None of DCP Midstream, LLC nor any of its affiliates, including
Spectra Energy and ConocoPhillips, is restricted, under either
our partnership agreement or the Omnibus Agreement, from
competing with us. DCP Midstream, LLC and any of its affiliates,
including Spectra Energy and ConocoPhillips, may acquire,
construct or dispose of additional midstream energy or other
assets in the future without any obligation to offer us the
opportunity to purchase or construct those assets.
Indemnification
DCP Midstream, LLC agreed to indemnify us for up to
$5.3 million of our pro rata share of any capital
contributions associated with repairing the Black Lake pipeline
that are determined to be necessary as a result of the pipeline
integrity testing. We anticipate repairs of approximately
$0.8 million on the pipeline, which will be funded directly
from Black Lake. We will not make contributions to Black Lake to
cover these expenses.
In connection with our acquisition of our wholesale propane
logistics business, DCP Midstream, LLC agreed to indemnify us
until October 31, 2009 for any claims for fines or
penalties of any governmental authority for periods prior to the
closing, agreed to indemnify us until October 31, 2010 if
certain contractual matters result in a claim, and agreed to
indemnify us indefinitely for breaches of the agreement. The
indemnity obligation for breach of the representations and
warranties is not effective until claims exceed in the aggregate
$680,000 and is subject to a maximum liability of
$6.8 million. This indemnity obligation for all other
claims other than a breach of the representations and warranties
does not become effective until an individual claim or series of
related claims exceed $50,000.
In connection with our acquisitions of East Texas and Discovery
from DCP Midstream, LLC, DCP Midstream, LLC agreed to indemnify
us until July 1, 2009 for any claims for fines or penalties
of any governmental authority for periods prior to the closing
and that are associated with certain East Texas assets that were
formerly owned by Gulf South and UP Fuels, and agreed to
indemnify us indefinitely for breaches of the agreement and
certain existing claims. The indemnity obligation for breach of
the representations and warranties is not effective until claims
exceed in the aggregate $2.7 million and is subject to a
maximum liability of $27.0 million. This indemnity
obligation for all other claims other than a breach of the
representations and warranties does not become effective until
an individual claim or series of related claims exceed $50,000.
In connection with our acquisition of certain subsidiaries of
MEG, DCP Midstream agreed to indemnify us until August 29,
2008 for any breach of the representations and warranties
(except certain corporate related matters that survive
indefinitely), and indefinitely for breaches of the agreement.
We have not pursued indemnification under these agreements.
Contracts
with Affiliates
We charge transportation fees, sell a portion of our residue gas
and NGLs to, and purchase natural gas and NGLs from, DCP
Midstream, LLC, ConocoPhillips, and their respective affiliates.
We also purchase a portion of our propane from and market
propane on behalf of Spectra Energy. Management anticipates
continuing to purchase and sell these commodities to DCP
Midstream, LLC, ConocoPhillips and their respective affiliates,
and Spectra Energy in the ordinary course of business.
Natural
Gas Gathering and Processing Arrangements
We have a fee-based contractual relationship with
ConocoPhillips, which includes multiple contracts, pursuant to
which ConocoPhillips has dedicated all of its natural gas
production within an area of mutual interest to our Ada, Minden
and Pelico systems under multiple agreements that have terms of
up to five years and are market based. These agreements provide
for the gathering, processing and transportation services at our
Ada and Minden gathering and processing systems and the Pelico
system. At our Ada gathering and processing system, we collect
fees from ConocoPhillips for gathering and compressing the
natural gas from the wellhead or receipt point and processing
the natural gas at the Ada processing plant. At our Minden
gathering and processing system, we purchase natural gas from
ConocoPhillips at the wellhead or receipt
175
point, transport the wellhead natural gas through our gathering
system, treat and process the natural gas, and then sell the
resulting residue natural gas and NGLs at index prices based on
published index market prices. At our Pelico system, we collect
fees for compression and transportation services. Please read
Item 1. Business Natural Gas Services
Segment Customers and Contracts and
Note 5 of the Notes to Consolidated Financial Statements in
Item 8. Financial Statements and Supplementary
Data. One of these arrangements is set forth in a natural
gas gathering agreement dated June 1, 1987, as amended,
between DCP Assets Holding, LP (successor to the interest of
Cornerstone Natural Gas Company) and ConocoPhillips (successor
to interest of Phillips Petroleum Company). We succeeded to the
rights and obligations of DCP Assets Holding, LP under this
agreement upon the closing of our initial public offering.
Pursuant to this agreement, we receive gathering and compression
fees from ConocoPhillips with respect to natural gas produced by
ConocoPhillips that we gather and compress in our Ada gathering
system from wells located in a designated area of mutual
interest located in northern Louisiana covering approximately
54 square miles. The fees we receive are based on market
rates for these types of services. To date, ConocoPhillips has
drilled and connected approximately 180 wells to our Ada
gathering system pursuant to this contract. This agreement
expires in 2011. Please read Note 5 of the Notes to
Consolidated Financial Statements in Item 8.
Financial Statements and Supplementary Data.
Merchant
Arrangements
Under our merchant arrangements, we use a subsidiary of DCP
Midstream, LLC (DCP Midstream Marketing, LP) as our agent to
purchase natural gas from third parties at pipeline interconnect
points, as well as residue gas from our Minden and Ada
processing plants, and then resell the aggregated natural gas
primarily to third parties. In the case of certain industrial
end-user customers, from time to time we may sell aggregated
natural gas to a subsidiary of DCP Midstream, LLC, which in turn
would resell natural gas to these customers. Under these
arrangements, we expect that this subsidiary of DCP Midstream,
LLC would make a profit on these sales. We have also entered
into a contractual arrangement with a subsidiary of DCP
Midstream, LLC that requires DCP Midstream, LLC to supply
Pelicos system requirements that exceed its on-system
supply. Accordingly, DCP Midstream, LLC purchases natural gas
and transports it to our Pelico system, where we buy the gas
from DCP Midstream, LLC at the actual acquisition cost plus
transportation service charges incurred. If our Pelico system
has volumes in excess of the on-system demand, DCP Midstream,
LLC will purchase the excess natural gas from us and transport
it to sales points at an index-based price less a contractually
agreed to marketing fee. In addition, DCP Midstream, LLC may
purchase other excess natural gas volumes at certain Pelico
outlets for a price that equals the original Pelico purchase
price from DCP Midstream, LLC plus a portion of the index
differential between upstream sources to certain downstream
indices with a maximum differential and a minimum differential
plus a fixed fuel charge and other related adjustments. We also
sell our NGLs at the Minden processing plant to a subsidiary of
DCP Midstream, LLC (DCP NGL Services, LP) who then transports
the NGLs on the Black Lake pipeline. Please read Note 5 of
the Notes to Consolidated Financial Statements in Item 8.
Financial Statements and Supplementary Data.
Propane
Supply Arrangements
During the second quarter of 2008, we entered into a propane
supply agreement with Spectra Energy. This agreement, effective
May 1, 2008 and terminating April 30, 2014, provides
us propane supply at our marine terminal, which is included in
our Wholesale Propane Logistics segment, for up to approximately
120 million gallons of propane annually. This contract
replaces the supply provided under a contract with a third party
that was terminated for non-performance during the first quarter
of 2008.
Transportation
Arrangements
Effective December 2005, we entered into a long-term, fee-based
contractual arrangement with a subsidiary of DCP Midstream, LLC
(DCP NGL Services, LP) that provided that the DCP Midstream, LLC
subsidiary will pay us to transport NGLs on our Seabreeze
pipeline pursuant to a fee-based rate that will be applied to
the volumes transported. Under this agreement, we are required
to reserve sufficient capacity in the Seabreeze pipeline to
ensure our ability to accept up to 38,000 Bbls/d of NGLs
tendered by the DCP Midstream, LLC subsidiary each day prior to
utilizing the excess capacity for our own use or for that of any
176
third parties, and the DCP Midstream, LLC subsidiary is required
to tender all NGLs processed at certain plants that it owns,
controls or otherwise has an obligation to market for others.
DCP Midstream, LLC historically is also the largest shipper on
the Black Lake pipeline, primarily due to the NGLs delivered to
it from our Minden processing plant. Please read Note 5 of
the Notes to Consolidated Financial Statements in Item 8.
Financial Statements and Supplementary Data.
Derivative
Arrangements
We have entered into long-term natural gas and crude oil swap
contracts whereby we receive a fixed price for natural gas and
crude oil and we pay a floating price. DCP Midstream, LLC has
issued guarantees to our counterparties in those transactions
that were in effect at the time of our initial public offering.
With this credit support, we have more favorable collateral
terms than we would have otherwise received. For more
information regarding our derivative activities and credit
support provided by DCP Midstream, LLC, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Quantitative and
Qualitative Disclosures about Market Risk Commodity
Price Risk Commodity Cash Flow Protection
Activities and Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
Other
Agreements and Transactions with DCP Midstream,
LLC
In December 2006, we completed construction of our Wilbreeze
pipeline, which connects a DCP Midstream, LLC gas processing
plant to our Seabreeze pipeline. The project is supported by an
NGL product dedication agreement with DCP Midstream, LLC.
In the second quarter of 2006, we entered into a letter
agreement with DCP Midstream, LLC whereby DCP Midstream, LLC
will make capital contributions to us as reimbursement for
capital projects, which were forecasted to be completed prior to
our initial public offering, but were not completed by that
date. Pursuant to the letter agreement, DCP Midstream, LLC made
capital contributions to us of $3.4 million during 2006 and
$0.3 million during 2007, to reimburse us for the capital
costs we incurred, primarily for growth capital projects.
In conjunction with our acquisition of a 40% limited liability
company interest in Discovery from DCP Midstream, LLC in July
2007, we entered into a letter agreement with DCP Midstream, LLC
whereby DCP Midstream, LLC will make capital contributions to us
as reimbursement for certain Discovery capital projects, which
were forecasted to be completed prior to our acquisition of a
40% limited liability company interest in Discovery. Pursuant to
the letter agreement, DCP Midstream, LLC made capital
contributions to us of $3.8 million and $0.3 million
during 2008 and 2007, respectively, to reimburse us for these
capital projects, which were substantially completed in 2008.
Review,
Approval or Ratification of Transactions with Related
Persons
Our partnership agreement contains specific provisions that
address potential conflicts of interest between the owner of our
general partner and its affiliates, including DCP Midstream, on
one hand, and us and our subsidiaries, on the other hand.
Whenever such a conflict of interest arises, our general partner
will resolve the conflict. Our general partner may, but is not
required to, seek the approval of such resolution from the
special committee of the board of directors of our general
partner, which is comprised of independent directors and acts as
our conflicts committee. The partnership agreement provides that
our general partner will not be in breach of its obligations
under the partnership agreement or its duties to us or to our
unitholders if the resolution of the conflict is:
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approved by the conflicts committee;
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of
the relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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177
If our general partner does not seek approval from the special
committee and the board of directors of our general partner
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third and fourth bullet points above,
then it will be presumed that, in making its decision, the board
of directors acted in good faith, and in any proceeding brought
by or on behalf of any limited partner or the partnership, the
person bringing or prosecuting such proceeding will have the
burden of overcoming such presumption. Unless the resolution of
a conflict is specifically provided for in our partnership
agreement, our general partner or the conflicts committee may
consider any factors it determines in good faith to consider
when resolving a conflict. When our partnership agreement
requires someone to act in good faith, it requires that person
to reasonably believe that he is acting in the best interests of
the partnership, unless the context otherwise requires.
In addition, our code of business ethics requires that all
employees, including employees of affiliates of DCP Midstream
who perform services for us and our general partner, avoid or
disclose any activity that may interfere, or have the appearance
of interfering, with their responsibilities to us.
Director
Independence
Please see Item 10. Directors, Executive Officers and
Corporate Governance for information about the
independence of our general partners board of directors
and its committees, which information is incorporated herein by
reference in its entirety.
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Item 14.
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Principal
Accounting Fees and Services
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The following table presents fees for professional services
rendered by Deloitte & Touche LLP, or Deloitte, our
principal accountant, for the audit of our financial statements,
and the fees billed for other services rendered by Deloitte:
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Year Ended December 31,
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Type of Fees
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2008
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2007
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(Millions)
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Audit Fees(a)
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$
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1.6
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$
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1.9
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(a) |
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Audit Fees are fees billed by Deloitte for professional services
for the audit of our consolidated financial statements included
in our annual report on
Form 10-K
and review of financial statements included in our quarterly
reports on
Form 10-Q,
services that are normally provided by Deloitte in connection
with statutory and regulatory filings or engagements or any
other service performed by Deloitte to comply with generally
accepted auditing standards and include comfort and consent
letters in connection with Securities and Exchange Commission
filings and financing transactions. |
For the last two fiscal years, Deloitte has not billed us for
assurance and related services, unless such services were
reasonably related to the performance of the audit or review of
our financial statements, and are included in the table above.
Deloitte has not provided any services to us over the last two
fiscal years related to tax compliance, tax services and tax
planning.
Audit
Committee Pre-Approval Policy
The audit committee pre-approves all audit and permissible
non-audit services provided by the independent auditors on a
case-by-case
basis. These services may include audit services, audit-related
services, tax services and other services. The audit committee
does not delegate its responsibilities to pre-approve services
performed by the independent auditor to management or to an
individual member of the audit committee. The audit committee
has, however, pre-approved audit related services that do not
impair the independence of the independent auditors for up to
$50,000 per engagement, and up to an aggregate of $200,000
annually, provided the audit committee is notified of such
audit-related services in a timely manner. The audit committee
may, however, from time to time delegate its authority to any
audit committee member, who will report on the independent
auditor services that were approved at the next audit committee
meeting.
178
PART IV
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Item 15.
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Exhibits
and Financial Statement Schedules
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Consolidated Financial Statements and Financial Statements
Schedules included in this Item 15:
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(a)
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Schedule II Consolidated Valuation and
Qualifying Accounts and Reserves
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(b)
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Consolidated Financial Statements of Discovery Producer Services
LLC and Financial Statements of DCP East Texas Holdings, LLC
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(a) |
Financial Statement Schedules
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DCP
MIDSTREAM PARTNERS, LP
SCHEDULE II
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND
RESERVES
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Charged to
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Credit to
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Balance at
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Consolidated
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Charged to
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Consolidated
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Balance at
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Beginning of
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Statements of
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Other
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Deductions/
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Statements of
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End of
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Period
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Operations
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Accounts(a)
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Other
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Operations
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Period
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(Millions)
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December 31, 2008
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Allowance for doubtful accounts
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$
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1.2
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$
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(0.5
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$
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$
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(0.1
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$
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$
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0.6
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Environmental
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1.7
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0.5
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(0.3
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)
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1.9
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Other(b)
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2.6
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2.6
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$
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2.9
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$
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2.6
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$
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$
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(0.4
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)
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$
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$
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5.1
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December 31, 2007
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Allowance for doubtful accounts
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$
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0.3
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$
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0.8
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$
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0.2
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$
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(0.1
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$
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$
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1.2
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Environmental
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0.1
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0.1
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1.6
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(0.1
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1.7
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Other(b)
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0.3
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(0.3
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$
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0.7
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$
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0.9
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$
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1.8
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$
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(0.5
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)
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$
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$
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2.9
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December 31, 2006
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Allowance for doubtful accounts
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$
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0.3
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$
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0.3
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$
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$
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(0.3
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)
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$
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$
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0.3
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Environmental
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0.1
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0.1
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Other(b)
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0.3
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0.3
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$
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0.4
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$
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0.6
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$
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$
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(0.3
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)
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$
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$
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0.7
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(a) |
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Related to acquisition of certain subsidiaries of Momentum
Energy Group, Inc. |
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(b) |
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Principally consists of other contingency liabilities, which are
included in other current liabilities. |
179
Discovery
Producer Services LLC
Consolidated
Financial Statements
For the
Years Ended December 31, 2008, 2007 and 2006
180
Report of
Independent Registered Public Accounting Firm
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of
Discovery Producer Services LLC as of December 31, 2008 and
2007, and the related consolidated statements of income,
members capital, and cash flows for each of the three
years in the period ended December 31, 2008. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Discovery Producer Services LLC at
December 31, 2008 and 2007, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
/s/ Ernst &Young LLP
Tulsa, Oklahoma
February 23, 2009
181
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
BALANCE SHEETS
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December 31,
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2008
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2007
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(In thousands)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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42,052
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$
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38,509
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Trade accounts receivable:
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Affiliate
|
|
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202
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|
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|
22,467
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Other
|
|
|
1,899
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|
|
|
5,847
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Insurance receivable
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|
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3,373
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|
|
|
5,692
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Inventory
|
|
|
519
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|
|
|
483
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Other current assets
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2,933
|
|
|
|
5,037
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|
|
|
|
|
|
|
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Total current assets
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50,978
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|
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78,035
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Restricted cash
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3,470
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|
|
6,222
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Property, plant, and equipment, net
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370,482
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|
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368,228
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|
|
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Total assets
|
|
$
|
424,930
|
|
|
$
|
452,485
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LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
3,125
|
|
|
$
|
8,106
|
|
Other
|
|
|
34,779
|
|
|
|
17,617
|
|
Accrued liabilities
|
|
|
5,714
|
|
|
|
6,439
|
|
Other current liabilities
|
|
|
1,616
|
|
|
|
1,658
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
45,234
|
|
|
|
33,820
|
|
Noncurrent accrued liabilities
|
|
|
19,771
|
|
|
|
12,216
|
|
Members capital
|
|
|
359,925
|
|
|
|
406,449
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
424,930
|
|
|
$
|
452,485
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
182
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
207,706
|
|
|
$
|
216,889
|
|
|
$
|
148,385
|
|
Third-party
|
|
|
1,324
|
|
|
|
5,251
|
|
|
|
|
|
Gas and condensate transportation services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
782
|
|
|
|
979
|
|
|
|
3,835
|
|
Third-party
|
|
|
13,308
|
|
|
|
15,553
|
|
|
|
14,668
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
1,506
|
|
|
|
3,092
|
|
|
|
8,605
|
|
Third-party
|
|
|
12,709
|
|
|
|
17,767
|
|
|
|
19,473
|
|
Other revenues
|
|
|
3,913
|
|
|
|
1,141
|
|
|
|
2,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
241,248
|
|
|
|
260,672
|
|
|
|
197,313
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
83,576
|
|
|
|
93,722
|
|
|
|
66,890
|
|
Third-party
|
|
|
63,422
|
|
|
|
61,982
|
|
|
|
52,662
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
8,836
|
|
|
|
5,579
|
|
|
|
5,276
|
|
Third-party
|
|
|
27,834
|
|
|
|
23,409
|
|
|
|
17,773
|
|
Depreciation and accretion
|
|
|
21,324
|
|
|
|
25,952
|
|
|
|
25,562
|
|
Taxes other than income
|
|
|
1,439
|
|
|
|
1,330
|
|
|
|
1,114
|
|
General and administrative expenses affiliate
|
|
|
4,500
|
|
|
|
2,280
|
|
|
|
2,150
|
|
Other (income) expense, net
|
|
|
(3,511
|
)
|
|
|
534
|
|
|
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
207,420
|
|
|
|
214,788
|
|
|
|
171,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
33,828
|
|
|
|
45,884
|
|
|
|
25,603
|
|
Interest income
|
|
|
(650
|
)
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
Foreign exchange (gain) loss
|
|
|
78
|
|
|
|
(388
|
)
|
|
|
(2,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
183
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams
|
|
|
Partners
|
|
|
DCP Assets
|
|
|
|
|
|
|
|
|
|
Energy,
|
|
|
Operating
|
|
|
Holding,
|
|
|
|
|
|
|
|
|
|
L.L.C.
|
|
|
LLC
|
|
|
LP
|
|
|
Total
|
|
|
|
|
|
Balance, December 31, 2005
|
|
$
|
87,806
|
|
|
$
|
170,532
|
|
|
$
|
155,298
|
|
|
$
|
413,636
|
|
|
|
|
|
Contributions
|
|
|
800
|
|
|
|
1,600
|
|
|
|
11,109
|
|
|
|
13,509
|
|
|
|
|
|
Distributions
|
|
|
(10,798
|
)
|
|
|
(16,400
|
)
|
|
|
(16,400
|
)
|
|
|
(43,598
|
)
|
|
|
|
|
Net income
|
|
|
6,017
|
|
|
|
12,033
|
|
|
|
12,033
|
|
|
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
83,825
|
|
|
|
167,765
|
|
|
|
162,040
|
|
|
|
413,630
|
|
|
|
|
|
Contributions
|
|
|
|
|
|
|
|
|
|
|
3,920
|
|
|
|
3,920
|
|
|
|
|
|
Distributions
|
|
|
(7,233
|
)
|
|
|
(28,270
|
)
|
|
|
(23,669
|
)
|
|
|
(59,172
|
)
|
|
|
|
|
Net income
|
|
|
2,602
|
|
|
|
26,241
|
|
|
|
19,228
|
|
|
|
48,071
|
|
|
|
|
|
Sale of Williams Energy, L.L.C.s 20% interest to Williams
Partners Operating LLC
|
|
|
(79,194
|
)
|
|
|
79,194
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
|
|
|
|
244,930
|
|
|
|
161,519
|
|
|
|
406,449
|
|
|
|
|
|
Contributions
|
|
|
|
|
|
|
5,700
|
|
|
|
7,376
|
|
|
|
13,076
|
|
|
|
|
|
Distributions
|
|
|
|
|
|
|
(56,400
|
)
|
|
|
(37,600
|
)
|
|
|
(94,000
|
)
|
|
|
|
|
Net income
|
|
|
|
|
|
|
20,641
|
|
|
|
13,759
|
|
|
|
34,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
|
|
|
$
|
214,871
|
|
|
$
|
145,054
|
|
|
$
|
359,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
184
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
21,324
|
|
|
|
25,952
|
|
|
|
25,562
|
|
Net loss on disposal of equipment
|
|
|
175
|
|
|
|
603
|
|
|
|
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
26,213
|
|
|
|
(9,389
|
)
|
|
|
26,599
|
|
Insurance receivable
|
|
|
2,319
|
|
|
|
6,931
|
|
|
|
(12,147
|
)
|
Inventory
|
|
|
(36
|
)
|
|
|
93
|
|
|
|
348
|
|
Other current assets
|
|
|
2,104
|
|
|
|
(802
|
)
|
|
|
(1,911
|
)
|
Accounts payable
|
|
|
5,932
|
|
|
|
(7,540
|
)
|
|
|
(6,062
|
)
|
Accrued liabilities
|
|
|
(725
|
)
|
|
|
1,320
|
|
|
|
(1,086
|
)
|
Other current liabilities
|
|
|
(52
|
)
|
|
|
(3,147
|
)
|
|
|
2,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
91,654
|
|
|
|
62,092
|
|
|
|
63,456
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in restricted cash
|
|
|
2,752
|
|
|
|
22,551
|
|
|
|
15,786
|
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(16,188
|
)
|
|
|
(31,739
|
)
|
|
|
(33,516
|
)
|
Proceeds from sale of property, plant and equipment
|
|
|
|
|
|
|
649
|
|
|
|
|
|
Change in accounts payable capital expenditures
|
|
|
6,249
|
|
|
|
2,625
|
|
|
|
568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(7,187
|
)
|
|
|
(5,914
|
)
|
|
|
(17,162
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to members
|
|
|
(94,000
|
)
|
|
|
(59,172
|
)
|
|
|
(43,598
|
)
|
Capital contributions
|
|
|
13,076
|
|
|
|
3,920
|
|
|
|
13,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(80,924
|
)
|
|
|
(55,252
|
)
|
|
|
(30,089
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
3,543
|
|
|
|
926
|
|
|
|
16,205
|
|
Cash and cash equivalents at beginning of period
|
|
|
38,509
|
|
|
|
37,583
|
|
|
|
21,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
42,052
|
|
|
$
|
38,509
|
|
|
$
|
37,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
185
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1.
|
Organization
and Description of Business
|
Our company consists of Discovery Producer Services LLC (DPS) a
Delaware limited liability company formed on June 24, 1996,
and its wholly owned subsidiary, Discovery Gas Transmission LLC
(DGT) a Delaware limited liability company also formed on
June 24, 1996. DPS was formed for the purpose of
constructing and operating a 600 million cubic feet per day
(MMcf/d)
cryogenic natural gas processing plant near Larose, Louisiana
and a 32,000 barrel per day (bpd) natural gas liquids
fractionator near Paradis, Louisiana. DGT was formed for the
purpose of constructing and operating a natural gas pipeline
from offshore deep water in the Gulf of Mexico to DPSs gas
processing plant in Larose, Louisiana. The mainline has a design
capacity of
600 MMcf/d
and consists of approximately 105 miles of pipe. DPS has
since connected several laterals to the DGT pipeline to expand
its presence in the Gulf. Herein, DPS and DGT are collectively
referred to in the first person as we,
us or our and sometimes as the
Company.
At the beginning of the periods presented, we were owned 20% by
Williams Energy, L.L.C. (a wholly owned subsidiary of The
Williams Companies, Inc.), 40% by DCP Assets, LP (DCP) and 40%
by Williams Partners Operating LLC (a wholly owned subsidiary of
Williams Partners L.P) (WPZ). Williams Energy, L.L.C. is our
operator. Herein, The Williams Companies, Inc. and its
subsidiaries are collectively referred to as
Williams.
On June 28, 2007, WPZ acquired the 20% interest in us
previously held by Williams Energy, L.L.C. Hence, at
December 31, 2007, we are owned 60% by WPZ and 40% by DCP.
|
|
Note 2.
|
Summary
of Significant Accounting Policies
|
Basis of Presentation. The consolidated
financial statements have been prepared based upon accounting
principles generally accepted in the United States and include
the accounts of DPS and its wholly owned subsidiary, DGT.
Intercompany accounts and transactions have been eliminated.
Use of Estimates. The preparation of
consolidated financial statements in conformity with accounting
principles generally accepted in the United States requires
management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and
accompanying notes. Actual results could differ from those
estimates.
Estimates and assumptions used in the calculation of asset
retirement obligations are, in the opinion of management,
significant to the underlying amounts included in the
consolidated financial statements. It is reasonably possible
that future events or information could change those estimates.
Cash and Cash Equivalents. The cash and cash
equivalent balance is primarily invested in funds with
high-quality, short term securities and instruments that are
issued or guaranteed by the U.S. government. These
securities have maturities of three months or less when acquired.
Trade Accounts Receivable. Trade accounts
receivable are carried on a gross basis, with no discounting,
less an allowance for doubtful accounts. We do not recognize an
allowance for doubtful accounts at the time the revenue that
generates the accounts receivable is recognized. We estimate the
allowance for doubtful accounts based on existing economic
conditions, the financial condition of the customers, and the
amount and age of past due accounts. Receivables are considered
past due if full payment is not received by the contractual due
date. Past due accounts are generally written off against the
allowance for doubtful accounts only after all collection
attempts have been exhausted. There was no allowance for
doubtful accounts at December 31, 2008 and 2007.
Insurance Receivable. Hurricane Katrina
damaged our pipeline and onshore facilities in 2005, and
Hurricane Ike damaged the 30 mainline and 18 lateral
in 2008. Expenditures incurred for the repair of these damages
which are probable for recovery when incurred are recorded as
insurance receivable. We expense
186
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
expenditures up to the insurance deductible ($6.4 million
in 2008), amounts not covered by insurance ($2.0 million in
2008) and amounts subsequently determined not to be
recoverable.
Gas Imbalances. In the course of providing
transportation services to customers, DGT may receive different
quantities of gas from shippers than the quantities delivered on
behalf of those shippers. This results in gas transportation
imbalance receivables and payables which are recovered or repaid
in cash, based on market-based prices, or through the receipt or
delivery of gas in the future. Imbalance receivables and
payables are included in Other current assets and Other current
liabilities in the Consolidated Balance Sheets. Imbalance
receivables are valued based on the lower of the current market
prices or weighted average cost of natural gas in the system.
Imbalance payables are valued at current market prices.
Settlement of imbalances requires agreement between the
pipelines and shippers as to allocations of volumes to specific
transportation contracts and the timing of delivery of gas based
on operational conditions. Pursuant to a settlement with our
shippers issued by the Federal Energy Regulatory Commission on
February 5, 2008, if a cash-out refund is due and payable
to a shipper during any year pursuant to Transporters FERC
Gas Tariff, shipper will be deemed to have immediately assigned
its right to the refund amount to us.
Inventory. Inventory includes fractionated
products at our Paradis facility and is carried at the lower of
cost or market. Cost is determined based on the weighted average
natural gas shrink replacement cost.
Restricted Cash. Restricted cash within
non-current assets relates to escrow funds contributed by our
members for the construction of the Tahiti pipeline lateral
expansion. The restricted cash is classified as non-current
because the funds will be used to construct a long-term asset.
The restricted cash is primarily invested in short-term money
market accounts with financial institutions.
Property, Plant and Equipment. Property, plant
and equipment is recorded at cost. We base the carrying value of
these assets on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values. The natural
gas and natural gas liquids maintained in the pipeline
facilities necessary for their operation (line fill) are
included in property, plant and equipment. Depreciation of
property, plant and equipment is provided on a straight-line
basis over the estimated useful lives of 25 to 35 years.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that extend the useful lives of the
assets or increase their functionality are capitalized. The cost
of property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in the Statements
of Income.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation (ARO). The ARO
asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure
changes in the liability due to passage of time by applying an
interest method of allocation. This amount is recognized as an
increase in the carrying amount of the liability and as
corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of
products is recognized in the period of delivery, and revenues
from the gathering, transportation and processing of gas are
recognized in the period the service is provided based on
contractual terms and the related natural gas and liquid
volumes. DGT is subject to Federal Energy Regulatory Commission
(FERC) regulations, and accordingly, certain revenues collected
may be subject to possible refunds upon final orders in pending
cases. DGT records rate refund liabilities considering its and
other third parties regulatory proceedings, advice of counsel,
estimated total exposure as discounted and risk weighted, and
collection and other risks. There were no rate refund
liabilities accrued at December 31, 2008 or 2007.
Impairment of Long-Lived Assets. We evaluate
long-lived assets for impairment on an individual asset or asset
group basis when events or changes in circumstances indicate
that, in our managements judgment, the carrying value of
such assets may not be recoverable. When such a determination
has been made, we compare our managements estimate of
undiscounted future cash flows attributable to the assets to the
carrying
187
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
value of the assets to determine whether the carrying value is
recoverable. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
Income Taxes. For federal tax purposes, we
have elected to be treated as a partnership with each member
being separately taxed on its ratable share of our taxable
income. This election, to be treated as a pass-through entity,
also applies to our wholly owned subsidiary, DGT. Therefore, no
income taxes or deferred income taxes are reflected in the
consolidated financial statements.
Foreign Currency Transactions. Transactions
denominated in currencies other than the functional currency are
recorded based on exchange rates at the time such transactions
arise. Subsequent changes in exchange rates result in
transaction gains or losses which are reflected in the
Consolidated Statements of Income.
|
|
Note 3.
|
Related
Party Transactions
|
We have various business transactions with our members and
subsidiaries and affiliates of our members. Revenues include the
following:
|
|
|
|
|
sales to Williams of NGLs to which we take title and excess gas
at current market prices for the products and
|
|
|
|
processing and sales of natural gas liquids and transportation
of gas and condensate for DCPs affiliates, Texas Eastern
Corporation and ConocoPhillips Company.
|
The following table summarizes these related-party revenues
during 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Williams
|
|
$
|
207,782
|
|
|
$
|
217,012
|
|
|
$
|
148,543
|
|
Texas Eastern Corporation
|
|
|
1,953
|
|
|
|
3,912
|
|
|
|
12,282
|
|
ConocoPhillips
|
|
|
259
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
209,994
|
|
|
$
|
220,960
|
|
|
$
|
160,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have no employees. Pipeline and plant operations are
performed under operation and maintenance agreements with
Williams. Most costs for materials, services and other charges
are third-party charges and are invoiced directly to us.
Operating and maintenance expenses affiliate includes
the following:
|
|
|
|
|
direct payroll and employee benefit costs incurred on our behalf
by Williams, and
|
|
|
|
rental expense under a
10-year
leasing agreement for pipeline capacity through 2015 from Texas
Eastern Transmission, LP (an affiliate of DCP)
|
Product costs and shrink replacement affiliate
includes natural gas purchases from Williams for fuel and shrink
requirements made at market rates at the time of purchase.
General and administrative expenses affiliate
includes a monthly operation and management fee paid to Williams
to cover the cost of accounting services, computer systems and
management services provided to us.
188
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We also pay Williams a project management fee to cover the cost
of managing capital projects. This fee is determined on a
project by project basis and is capitalized as part of the
construction costs. A summary of the payroll costs and project
fees charged to us by Williams and capitalized are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Capitalized labor
|
|
$
|
317
|
|
|
$
|
222
|
|
|
$
|
373
|
|
Capitalized project fee
|
|
|
375
|
|
|
|
651
|
|
|
|
538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
692
|
|
|
$
|
873
|
|
|
$
|
911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 4.
|
Property,
Plant, and Equipment
|
Property, plant, and equipment consisted of the following at
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
Years Ended December 31,
|
|
|
Depreciable
|
|
|
|
2008
|
|
|
2007
|
|
|
Lives
|
|
|
|
(In thousands)
|
|
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction work in progress
|
|
$
|
76,302
|
|
|
$
|
66,550
|
|
|
|
|
|
Buildings
|
|
|
5,054
|
|
|
|
4,950
|
|
|
|
25 35 years
|
|
Land and land rights
|
|
|
5,575
|
|
|
|
2,491
|
|
|
|
0 35 years
|
|
Transportation lines
|
|
|
305,172
|
|
|
|
311,368
|
|
|
|
25 35 years
|
|
Plant and other equipment
|
|
|
216,189
|
|
|
|
200,722
|
|
|
|
25 35 years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant, and equipment
|
|
|
608,292
|
|
|
|
586,081
|
|
|
|
|
|
Less accumulated depreciation
|
|
|
237,810
|
|
|
|
217,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant, and equipment
|
|
$
|
370,482
|
|
|
$
|
368,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective July 1, 2008, we revised our estimate of the
useful lives of the Larose processing plant and the regulated
pipeline and gathering system. The annual depreciation expense
will decrease $13 million.
Commitments for construction and acquisition of property, plant,
and equipment for the Tahiti pipeline lateral expansion are
approximately $1.5 million at December 31, 2008.
Our asset retirement obligations relate primarily to our
offshore platform and pipelines and our onshore processing and
fractionation facilities. At the end of the useful life of each
respective asset, we are legally or contractually obligated to
dismantle the offshore platform, properly abandon the offshore
pipelines, remove the onshore facilities and related surface
equipment and restore the surface of the property.
189
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A rollforward of our asset retirement obligation for 2008 and
2007 is presented below.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Balance at January 1
|
|
$
|
12,118
|
|
|
$
|
3,728
|
|
Accretion expense
|
|
|
1,082
|
|
|
|
422
|
|
Estimate revisions
|
|
|
3,327
|
|
|
|
7,554
|
|
Liabilities incurred
|
|
|
3,157
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
19,684
|
|
|
$
|
12,118
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5.
|
Leasing
Activities
|
We lease the land on which the Paradis fractionator and the
Larose processing plant are located. The initial term of each
lease is 20 years with renewal options for an additional
30 years. We also have a ten-year leasing agreement for
pipeline capacity from Texas Eastern Transmission, LP that
includes renewal options and options to increase capacity which
would also increase rentals. On September 12, 2008, we
filed an amendment to the capacity lease agreement increasing
the leased capacity and resulting in a lease payment increase of
$380,000 annually. The future minimum annual rentals under these
non-cancelable leases as of December 31, 2008 are payable
as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
1,241
|
|
2010
|
|
|
1,241
|
|
2011
|
|
|
1,241
|
|
2012
|
|
|
1,241
|
|
2013
|
|
|
1,241
|
|
Thereafter
|
|
|
2,105
|
|
|
|
|
|
|
|
|
$
|
8,310
|
|
|
|
|
|
|
Total rent expense for 2008, 2007 and 2006, including a
cancelable platform space lease and month-to-month leases, was
$1.6 million, $1.4 million and $1.4 million,
respectively.
|
|
Note 6.
|
Financial
Instruments and Concentrations of Credit Risk
|
Financial
Instruments Fair Value
We used the following methods and assumptions to estimate the
fair value of financial instruments:
Cash and cash equivalents. The carrying
amounts reported in the consolidated balance sheets approximate
fair value due to the short-term maturity of these instruments.
Restricted cash. The carrying amounts reported
in the consolidated balance sheets approximate fair value as
these instruments have interest rates approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
42,052
|
|
|
$
|
42,052
|
|
|
$
|
38,509
|
|
|
$
|
38,509
|
|
Restricted cash
|
|
|
3,470
|
|
|
|
3,470
|
|
|
|
6,222
|
|
|
|
6,222
|
|
190
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Concentrations
of Credit Risk
Our cash equivalent balance is primarily invested in funds with
high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government.
At December 31, 2008, substantially all of our customer
accounts receivable result from gas transmission services
provided for our largest three customers. This concentration of
customers may impact our overall credit risk either positively
or negatively, in that these entities may be similarly affected
by industry-wide changes in economic or other conditions. As a
general policy, collateral is not required for receivables, but
customers financial condition and credit worthiness are
evaluated regularly. Our credit policy and the relatively short
duration of receivables mitigate the risk of uncollected
receivables. We did not incur any credit losses on receivables
during 2008 and 2007.
Major Customers. Williams accounted for
approximately $208.0 million (86%), $217.0 million
(83%), $149.8 million (75%) respectively, of our total
revenues in 2008, 2007 and 2006. These revenues were for the
sale of NGLs received as compensation under processing contracts
with third-party producers.
Note 7. Rate
and Regulatory Matters
Rate and Regulatory Matters. Annually, DGT
files a request with the FERC for a
lost-and-unaccounted-for
gas percentage to be allocated to shippers for the upcoming
fiscal year beginning July 1. On May 30, 2008, DGT
filed to maintain a
lost-and-unaccounted-for
percentage of zero percent until July 1, 2009 and to retain
the 2007 net system gains of $2.3 million that are
unrelated to the
lost-and-unaccounted-for
gas over recovered from its shippers. By Order dated
June 26, 2008 the filing was approved. The approval was
subject to a
30-day
protest period, which passed without protest. As of
December 31, 2008, and 2007, DGT has deferred amounts of
$5.5 million and $5.8 million, respectively, included
in current accrued liabilities in the accompanying Consolidated
Balance Sheets. The December 31, 2008 balance includes 2008
unrecognized net system gains. The December 31, 2007
balance represents amounts collected from customers pursuant to
prior years lost and unaccounted for gas percentage and
unrecognized net system gains.
On October 16, 2008, the FERC issued Order No. 717,
implementing standards of conduct for interstate pipelines and
marketing function employees of the interstate pipeline or of
the pipelines affiliates. The standards of conduct
preclude an interstate pipeline from any actions that might
provide any of its or its affiliates marketing function
employees with an unfair market advantage. The standards of
conduct only apply to natural gas transmission providers that
are affiliated with a marketing or brokering entity that
conducts transportation transactions on such natural gas
transmission providers pipeline. Currently DGTs
marketing or brokering affiliates do not conduct transmission
transactions on DGTs pipeline; therefore, the standards of
conduct are not currently applicable to DGT.
On November 16, 2007, DGT filed a petition for approval of
a settlement in lieu of a general rate change filing with FERC.
One shipper, ExxonMobil Gas & Power Marketing Company,
filed a protest. On February 5, 2008, the FERC issued an
order approving the settlement as to all parties except the
protesting ExxonMobil Gas & Power Marketing Company.
The settlement allowed Discovery to recognize the amounts
collected from customers pursuant to prior years lost and
unaccounted for gas of $3.5 million. The order is now final
and no longer subject to rehearing. DGT implemented the
settlement rates and surcharges effective January 1, 2008.
Environmental Matters. We are subject to
extensive federal, state, and local environmental laws and
regulations which affect our operations related to the
construction and operation of our facilities. Appropriate
governmental authorities may enforce these laws and regulations
with a variety of civil and criminal enforcement measures,
including monetary penalties, assessment and remediation
requirements and injunctions as to future compliance. We have
not been notified and are not currently aware of any material
noncompliance under the various environmental laws and
regulations.
191
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other. We are party to various other claims,
legal actions and complaints arising in the ordinary course of
business. Litigation, arbitration and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to
occur, there exists the possibility of a material adverse impact
on the results of operations in the period in which the ruling
occurs. Management, including internal counsel, currently
believes that the ultimate resolution of the foregoing matters,
taken as a whole, and after consideration of amounts accrued,
insurance coverage or other indemnification arrangements, will
not have a material adverse effect upon our future financial
position.
192
DCP East
Texas Holdings, LLC
Consolidated Financial Statements
For the Years Ended
December 31, 2008, 2007 and 2006
193
|
|
|
|
|
Deloitte & Touche LLP
Suite 3600
555 Seventeenth Street
Denver, CO
80202-3942
USA
|
|
|
|
|
|
Tel: +1 303 292 5400
Fax: +1 303 312 4000
www.deloitte.com
|
INDEPENDENT
AUDITORS REPORT
To the Board of Directors of
DCP Midstream, LLC
Denver, Colorado
We have audited the accompanying consolidated balance sheets of
DCP East Texas Holdings, LLC (the Company), as of
December 31, 2008 and 2007, and the related consolidated
statements of operations, changes in partners equity, and
cash flows for each of the three years in the period ended
December 31, 2008. Our audits also included the financial
statement schedule listed in the Index at Item 15. These
financial statements and financial statement schedule are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes consideration
of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company at December 31, 2008 and 2007, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
As described in Note 1 to the consolidated financial
statements, through July 1, 2007, the accompanying
consolidated financial statements have been prepared from the
separate records maintained by DCP Midstream, LLC and may not
necessarily be indicative of the conditions that would have
existed or the results of operations if the Company had been
operated as an unaffiliated entity. Portions of certain expenses
represent allocations made from, and are applicable to, DCP
Midstream, LLC as a whole.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 4, 2009
194
DCP EAST
TEXAS HOLDINGS, LLC
CONSOLIDATED
BALANCE SHEETS
(millions)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
13.9
|
|
|
$
|
4.8
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, net of allowance for doubtful accounts of
$0.4 million and $0.5 million, respectively
|
|
|
14.1
|
|
|
|
16.0
|
|
Affiliates
|
|
|
20.7
|
|
|
|
64.5
|
|
Other
|
|
|
1.1
|
|
|
|
0.8
|
|
Other
|
|
|
0.4
|
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
50.2
|
|
|
|
86.5
|
|
Property, plant and equipment, net
|
|
|
253.4
|
|
|
|
236.5
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
303.6
|
|
|
$
|
323.0
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
25.8
|
|
|
$
|
53.6
|
|
Affiliates
|
|
|
2.4
|
|
|
|
1.5
|
|
Other
|
|
|
0.9
|
|
|
|
2.9
|
|
Operating accrual
|
|
|
1.8
|
|
|
|
1.3
|
|
Capital spending accrual
|
|
|
5.1
|
|
|
|
2.7
|
|
Other
|
|
|
2.4
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
38.4
|
|
|
|
65.7
|
|
Deferred income taxes
|
|
|
1.7
|
|
|
|
1.7
|
|
Other long-term liabilities
|
|
|
0.6
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
40.7
|
|
|
|
67.9
|
|
Commitments and contingent liabilities
|
|
|
|
|
|
|
|
|
Partners equity
|
|
|
262.9
|
|
|
|
255.1
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity
|
|
$
|
303.6
|
|
|
$
|
323.0
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
195
DCP EAST
TEXAS HOLDINGS, LLC
CONSOLIDATED
STATEMENTS OF OPERATIONS
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, NGLs and condensate
|
|
$
|
202.8
|
|
|
$
|
179.8
|
|
|
$
|
177.7
|
|
Sales of natural gas, NGLs and condensate to affiliates
|
|
|
313.7
|
|
|
|
270.9
|
|
|
|
286.6
|
|
Transportation and processing services
|
|
|
28.7
|
|
|
|
22.2
|
|
|
|
21.9
|
|
Transportation and processing services to affiliates
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.3
|
|
Losses from non-trading derivative activity
affiliates
|
|
|
(0.6
|
)
|
|
|
(0.1
|
)
|
|
|
(1.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
544.8
|
|
|
|
472.9
|
|
|
|
485.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas and NGLs
|
|
|
419.7
|
|
|
|
357.8
|
|
|
|
376.0
|
|
Purchases of natural gas and NGLs from affiliates
|
|
|
0.1
|
|
|
|
1.1
|
|
|
|
9.3
|
|
Operating and maintenance expense
|
|
|
34.5
|
|
|
|
27.2
|
|
|
|
24.4
|
|
Depreciation expense
|
|
|
16.7
|
|
|
|
15.8
|
|
|
|
14.6
|
|
General and administrative expense
|
|
|
0.7
|
|
|
|
1.8
|
|
|
|
0.2
|
|
General and administrative expense affiliate
|
|
|
8.5
|
|
|
|
10.3
|
|
|
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
480.2
|
|
|
|
414.0
|
|
|
|
435.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
64.6
|
|
|
|
58.9
|
|
|
|
49.6
|
|
Interest income
|
|
|
0.4
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
65.0
|
|
|
|
59.2
|
|
|
|
49.6
|
|
Income tax expense
|
|
|
0.5
|
|
|
|
0.7
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
64.5
|
|
|
$
|
58.5
|
|
|
$
|
47.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
196
DCP EAST
TEXAS HOLDINGS, LLC
CONSOLIDATED
STATEMENTS OF CHANGES IN PARTNERS EQUITY
(millions)
|
|
|
|
|
Balance, January 1, 2006
|
|
$
|
194.0
|
|
Net change in parent advances
|
|
|
(38.1
|
)
|
Net income
|
|
|
47.8
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
203.7
|
|
Net change in parent advances
|
|
|
(17.1
|
)
|
Contributions
|
|
|
54.5
|
|
Distributions
|
|
|
(44.5
|
)
|
Net income
|
|
|
58.5
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
255.1
|
|
Contributions
|
|
|
29.5
|
|
Distributions
|
|
|
(86.2
|
)
|
Net income
|
|
|
64.5
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
$
|
262.9
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
197
DCP EAST
TEXAS HOLDINGS, LLC
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
64.5
|
|
|
$
|
58.5
|
|
|
$
|
47.8
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense
|
|
|
16.7
|
|
|
|
15.8
|
|
|
|
14.6
|
|
Deferred income taxes
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
1.8
|
|
Other, net
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
0.1
|
|
Change in operating assets and liabilities which provided (used)
cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
45.9
|
|
|
|
(50.6
|
)
|
|
|
0.3
|
|
Accounts payable
|
|
|
(28.7
|
)
|
|
|
10.2
|
|
|
|
(12.6
|
)
|
Other current assets and liabilities
|
|
|
(0.8
|
)
|
|
|
2.9
|
|
|
|
(1.0
|
)
|
Other non-current assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
(0.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
97.4
|
|
|
|
36.6
|
|
|
|
50.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(31.6
|
)
|
|
|
(24.5
|
)
|
|
|
(12.8
|
)
|
Proceeds from sales of assets
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(31.6
|
)
|
|
|
(24.5
|
)
|
|
|
(12.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in parent advances
|
|
|
|
|
|
|
(17.1
|
)
|
|
|
(38.1
|
)
|
Distributions
|
|
|
(86.2
|
)
|
|
|
(44.5
|
)
|
|
|
|
|
Contributions
|
|
|
29.5
|
|
|
|
54.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(56.7
|
)
|
|
|
(7.3
|
)
|
|
|
(38.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
9.1
|
|
|
|
4.8
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
4.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
13.9
|
|
|
$
|
4.8
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
198
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
1.
|
Description
of Business and Basis of Presentation
|
DCP East Texas Holdings, LLC, or East Texas, we, our, or us, is
a joint venture formed in July 2007 engaged in the business of
gathering, transporting, treating, compressing, processing, and
fractionating natural gas and natural gas liquids, or NGLs. Our
operations, located near Carthage, Texas, include a natural gas
processing complex with a total capacity of 780 million
cubic feet per day and a natural gas liquids fractionator. The
facility is connected to our about 900 mile gathering
system, as well as third party gathering systems. The complex is
adjacent to our Carthage Hub, which delivers residue gas to
interstate and intrastate pipelines. The Carthage Hub, with an
aggregate delivery capacity of 1.5 billion cubic feet per
day, acts as a key exchange point for the purchase and sale of
residue gas.
East Texas is owned 75% by DCP Midstream, LLC, or Midstream, and
25% by DCP Midstream Partners, LP, or Partners. The consolidated
financial statements include the accounts of East Texas and,
prior to July 1, 2007, the operations, assets and
liabilities contributed to us by Midstream, or the Business.
This was a transaction between entities under common control;
accordingly, our financial information includes the results for
all periods presented. Midstream is a joint venture owned 50% by
Spectra Energy Corp (which was spun off by Duke Energy
Corporation on January 2, 2007) and 50% by
ConocoPhillips. As of December 31, 2008, Midstream owns an
approximate 30% interest in Partners, which includes 100% of the
general partner interest. Midstream is currently appointed as
our operator and is responsible for
day-to-day
operation, maintenance and repair of our assets and the related
managerial and administrative duties. East Texas does not
currently, and does not expect to, have any employees.
The consolidated financial statements include the accounts of
East Texas and its wholly-owned subsidiaries and have been
prepared in accordance with accounting principles generally
accepted in the United States of America, or GAAP. The
consolidated financial statements of the Business were prepared
from the separate records maintained by Midstream prior to
July 1, 2007 and may not necessarily be indicative of the
conditions that would have existed, or the results of
operations, if the Business had been operated as an unaffiliated
entity. Because a direct ownership relationship did not exist
among all the various assets comprising East Texas until
July 1, 2007, Midstreams contributions and
distributions are shown as net change in parent advances in lieu
of contributions and distributions in the consolidated
statements of changes in partners equity. Transactions
between East Texas and other Midstream operations have been
identified in the consolidated financial statements as
transactions between affiliates. Intercompany balances and
transactions have been eliminated. In the opinion of management,
all adjustments have been reflected that are necessary for a
fair presentation of the consolidated financial statements.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Use of Estimates Conformity with
GAAP requires management to make estimates and assumptions that
affect the amounts reported in the consolidated financial
statements and notes. Although these estimates are based on
managements best available knowledge of current and
expected future events, actual results could differ from those
estimates.
Cash and Cash Equivalents Cash
and cash equivalents includes all cash balances and highly
liquid investments with an original maturity of three months or
less.
Fair Value of Financial
Instruments The fair value of accounts
receivable and accounts payable are not materially different
from their carrying amounts, due to the short-term nature of
these instruments. Unrealized gains and losses on non-trading
derivative instruments are recorded at fair value.
Accounting for Risk Management Activities and Financial
Instruments Each derivative not
qualifying for the normal purchases and normal sales exception
is recorded on a gross basis in the consolidated balance sheets
at its fair value as unrealized gains or unrealized losses on
derivative instruments. Derivative
199
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
assets and liabilities remain classified in the consolidated
balance sheets as unrealized gains or unrealized losses on
derivative instruments at fair value until the contractual
settlement period impacts earnings.
Our derivative activity includes normal purchase or normal sale
contracts, and non-trading derivative instruments related to
commodity prices. Normal purchase and normal sale contracts are
accounted for under the accrual method and are reflected in the
consolidated statements of operations in either sales or
purchases upon settlement. Other commodity non-trading
derivative instruments are accounted for under the
mark-to-market
method, whereby the change in the fair value of the asset or
liability is recognized in the consolidated statements of
operations in gains or losses from non-trading derivative
activity affiliates during the current period.
Valuation When available, quoted market
prices or prices obtained through external sources are used to
determine a contracts fair value. For contracts with a
delivery location or duration for which quoted market prices are
not available, fair value is determined based on pricing models
developed primarily from historical and expected correlations
with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the
transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period
under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of
these contracts. Accordingly, it is reasonably possible that
such estimates may change in the near term.
Property, Plant and
Equipment Property, plant and equipment
are recorded at original cost. The costs of maintenance and
repairs, which are not significant improvements, are expensed
when incurred. Depreciation is computed using the straight-line
method over the estimated useful lives of the assets.
Asset retirement obligations associated with tangible long-lived
assets are recorded at fair value in the period in which they
are incurred, if a reasonable estimate of fair value can be
made, and added to the carrying amount of the associated asset.
This additional carrying amount is then depreciated over the
life of the asset. The liability increases due to the passage of
time based on the time value of money until the obligation is
settled. We recognize a liability of a conditional asset
retirement obligation as soon as the fair value of the liability
can be reasonably estimated. A conditional asset retirement
obligation is defined as an unconditional legal obligation to
perform an asset retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity.
Long-Lived Assets We periodically
evaluate whether the carrying value of long-lived assets has
been impaired when circumstances indicate the carrying value of
those assets may not be recoverable. The carrying amount is not
recoverable if it exceeds the sum of the undiscounted cash flows
expected to result from the use and eventual disposition of the
asset. We consider various factors when determining if these
assets should be evaluated for impairment, including but not
limited to:
|
|
|
|
|
significant adverse change in legal factors or business climate;
|
|
|
|
a current-period operating or cash flow loss combined with a
history of operating or cash flow losses, or a projection or
forecast that demonstrates continuing losses associated with the
use of a long-lived asset;
|
|
|
|
an accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of a
long-lived asset;
|
|
|
|
significant adverse changes in the extent or manner in which an
asset is used, or in its physical condition;
|
|
|
|
a significant adverse change in the market value of an
asset; or
|
200
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
a current expectation that, more likely than not, an asset will
be sold or otherwise disposed of before the end of its estimated
useful life.
|
If the carrying value is not recoverable, the impairment loss is
measured as the excess of the assets carrying value over
its fair value. We assess the fair value of long-lived assets
using commonly accepted techniques, and may use more than one
method, including, but not limited to, recent third party
comparable sales, internally developed discounted cash flow
analysis and analyses from outside advisors. Significant changes
in market conditions resulting from events such as the condition
of an asset or a change in managements intent to utilize
the asset would generally require management to reassess the
cash flows related to the long-lived assets.
Revenue Recognition We generate
the majority of our revenues from natural gas gathering,
processing, compression, transportation, and fractionation of
natural gas and NGLs. We realize revenues either by selling the
residue natural gas and NGLs, or by receiving fees from the
producers.
We obtain access to raw natural gas and provide our midstream
natural gas services principally under contracts that contain a
combination of one or more of the following arrangements.
|
|
|
|
|
Fee-based arrangements Under fee-based
arrangements, we receive a fee or fees for one or more of the
following services: gathering, compressing, treating,
processing, or transporting of natural gas. Our fee-based
arrangements include natural gas purchase arrangements pursuant
to which we purchase natural gas at the wellhead, or other
receipt points, at an index related price at the delivery point
less a specified amount, generally the same as the fees we would
otherwise charge for gathering of natural gas from the wellhead
location to the delivery point. The revenue we earn is directly
related to the volume of natural gas that flows through our
systems and is not directly dependent on commodity prices. To
the extent a sustained decline in commodity prices results in a
decline in volumes, however, our revenues from these
arrangements would be reduced.
|
|
|
|
Percent-of-proceeds
arrangements Under
percent-of-proceeds
arrangements, we generally purchase natural gas from producers
at the wellhead, or other receipt points, gather the wellhead
natural gas through our gathering system, treat and process the
natural gas, and then sell the resulting residue natural gas and
NGLs based on index prices from published index market prices.
We remit to the producers either an
agreed-upon
percentage of the actual proceeds that we receive from our sales
of the residue natural gas and NGLs, or an
agreed-upon
percentage of the proceeds based on index related prices for the
natural gas and the NGLs, regardless of the actual amount of the
sales proceeds we receive. Certain of these arrangements may
also result in our returning all or a portion of the residue
natural gas
and/or the
NGLs to the producer, in lieu of returning sales proceeds. Our
revenues under
percent-of-proceeds
arrangements correlate directly with the price of natural gas
and/or NGLs.
|
|
|
|
Keep-whole arrangements Under the terms
of a keep-whole processing contract, we gather raw natural gas
from the producer for processing, sell the NGLs and return to
the producer residue natural gas with a British thermal unit, or
Btu, content equivalent to the Btu content of the natural gas
gathered. This arrangement keeps the producer whole to the
thermal value of the natural gas received. Under these types of
contracts, we are exposed to the frac spread. The
frac spread is the difference between the value of the NGLs
extracted from processing and the value of the Btu equivalent of
the residue natural gas. We benefit in periods when NGL prices
are higher relative to natural gas prices.
|
We recognize revenue for sales and services under the four
revenue recognition criteria, as follows:
|
|
|
|
|
Persuasive evidence of an arrangement exists
Our customary practice is to enter into a written contract,
executed by both us and the customer.
|
|
|
|
Delivery Delivery is deemed to have occurred
at the time custody is transferred, or in the case of fee-based
arrangements, when the services are rendered. To the extent we
retain product as inventory,
|
201
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
delivery occurs when the inventory is subsequently sold and
custody is transferred to the third party purchaser.
|
|
|
|
|
|
The fee is fixed or determinable We
negotiate the fee for our services at the outset of our
fee-based arrangements. In these arrangements, the fees are
nonrefundable. For other arrangements, the amount of revenue,
based on contractual terms, is determinable when the sale of the
applicable product has been completed upon delivery and transfer
of custody.
|
|
|
|
Collectibility is probable Collectibility is
evaluated on a
customer-by-customer
basis. New and existing customers are subject to a credit review
process, which evaluates the customers financial position
(for example, credit metrics, liquidity and credit rating) and
their ability to pay. If collectibility is not considered
probable at the outset of an arrangement in accordance with our
credit review process, revenue is recognized until the cash is
collected.
|
We generally report revenues gross in the consolidated
statements of operations, as we typically act as the principal
in these transactions, take custody to the product, and incur
the risks and rewards of ownership. Effective April 1,
2006, any new or amended contracts for certain sales and
purchases of inventory with the same counterparty, when entered
into in contemplation of one another, are reported net as one
transaction. We recognize revenues for non-trading derivative
activity in the consolidated statements of operations as gains
or losses from non-trading derivative activity
affiliates, including
mark-to-market
gains and losses and financial or physical settlement.
Quantities of natural gas or NGLs over-delivered or
under-delivered related to imbalance agreements with customers,
producers or pipelines are recorded monthly as other receivables
or other payables using current market prices or the
weighted-average prices of natural gas or NGLs at the plant or
system. These balances are settled with deliveries of natural
gas or NGLs, or with cash. Included in the consolidated balance
sheets as accounts receivable other as of
December 31, 2008 and 2007 were imbalances totaling
$1.1 million and $0.8 million, respectively. Included
in the consolidated balance sheets as accounts
payable other as of December 31, 2008 and 2007
were imbalances totaling $0.9 million and
$2.9 million, respectively.
Environmental
Expenditures Environmental expenditures
are expensed or capitalized as appropriate, depending upon the
future economic benefit. Expenditures that relate to an existing
condition caused by past operations, and that do not generate
current or future revenue, are expensed. Liabilities for these
expenditures are recorded on an undiscounted basis when
environmental assessments
and/or
clean-ups
are probable and the costs can be reasonably estimated.
Environmental liabilities are included in the consolidated
balances sheets as other current liabilities. There were no
environmental liabilities included in the consolidated balance
as of December 31, 2008 and 2007.
Income Taxes We are structured as
a joint venture which is a pass-through entity for federal
income tax purposes. Our income tax expense includes certain
jurisdictions, including state, local, franchise and margin
taxes of the joint venture and subsidiaries. We follow the asset
and liability method of accounting for income taxes. Under this
method, deferred income taxes are recognized for the tax
consequences of temporary differences between the financial
statement carrying amounts and the tax basis of the assets and
liabilities. East Texas is a member of a consolidated group. We
have calculated current and deferred income taxes as if we were
a separate taxpayer.
The Texas legislature replaced their franchise tax with a margin
tax system in May 2006. As of 2007, we are subject to the Texas
margin tax, which is treated as an income tax. Accordingly, we
recorded a deferred tax liability and related expense in 2008
and 2007, related to the temporary differences that are expected
to reverse in periods when the tax will apply.
202
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
3.
|
Recent
Accounting Pronouncements
|
Financial Accounting Standards Board, or FASB, Statement
of Financial Accounting Standards, or SFAS, No. 162
The Hierarchy of Generally Accepted Accounting
Principles, or SFAS 162 In
May 2008, the FASB issued SFAS 162, which is intended to
improve financial reporting by identifying a consistent
framework, or hierarchy, for selecting accounting principles to
be used in preparing financial statements that are presented in
conformity with GAAP for nongovernmental entities. SFAS 162
is effective 60 days following the Securities and Exchange
Commission, or SECs, approval of the Public Company
Accounting Oversight Board amendments to AU Section 411,
The Meaning of Present Fairly in Conformity with Generally
Accepted Accounting Principles. We have assessed the
impact of the adoption of SFAS 162, and believe that there
will be no impact on our consolidated results of operations,
cash flows or financial position.
SFAS No. 161 Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133 or
SFAS 161 In March 2008, the FASB
issued SFAS 161, which requires disclosures of how and why
an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for and how
derivative instruments and related hedged items affect an
entitys financial position, financial performance, and
cash flows. SFAS 161 is effective for us on January 1,
2009. We are in the process of assessing the impact of
SFAS 161 on our disclosures, and will make the required
disclosures in our December 31, 2009 consolidated financial
statements.
SFAS No. 141(R) Business Combinations
(revised 2007), or SFAS 141(R) In
December, 2007, the FASB issued SFAS 141(R), which requires
the acquiring entity in a business combination to recognize all
(and only) the assets acquired and liabilities assumed in the
transaction; establishes the acquisition-date fair value as the
measurement objective for all assets acquired and liabilities
assumed; and requires the acquirer to disclose to investors and
other users all of the information they need to evaluate and
understand the nature and financial effect of the business
combination. SFAS 141(R) is effective for us on
January 1, 2009. As this standard will be applied
prospectively upon adoption, we will account for all
transactions with closing dates subsequent to the adoption date
in accordance with the provisions of the standard.
SFAS, No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities including
an amendment of FAS 115, or
SFAS 159 In February 2007, the
FASB, issued SFAS 159, which allows entities to choose, at
specified election dates, to measure eligible financial assets
and liabilities at fair value that are not otherwise required to
be measured at fair value. If a company elects the fair value
option for an eligible item, changes in that items fair
value in subsequent reporting periods must be recognized in
current earnings. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparison between
entities that elect different measurement attributes for similar
assets and liabilities. SFAS 159 became effective for us on
January 1, 2008. We have not elected the fair value option
relative to any of our financial assets and liabilities which
are not otherwise required to be measured at fair value by other
accounting standards. Therefore, there is no effect of adoption
reflected in our consolidated results of operations, cash flows
or financial position.
SFAS No. 157, Fair Value
Measurements, or SFAS 157 In
September 2006, the FASB issued SFAS 157, which was
effective for us on January 1, 2008. SFAS 157:
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defines fair value as the price that would be received to sell
an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date;
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establishes a framework for measuring fair value;
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establishes a three-level hierarchy for fair value measurements
based upon the transparency of inputs to the valuation of an
asset or liability as of the measurement date;
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203
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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nullifies the guidance in Emerging Issues Task Force, or EITF,
02-3,
Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Involved in Energy Trading and Risk
Management Activities, which required the deferral of profit
at inception of a transaction involving a derivative financial
instrument in the absence of observable data supporting the
valuation technique; and
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significantly expands the disclosure requirements around
instruments measured at fair value.
|
Upon adoption of this standard we incorporated the marketplace
participant view as prescribed by SFAS 157. Such changes
included, but were not be limited to changes in valuation
policies to reflect an exit price methodology, the effect of
considering our own non-performance risk on the valuation of
liabilities, and the effect of any change in our credit rating
or standing. There has been no impact to our earnings as a
result of adopting SFAS 157. All changes in our valuation
methodology have been incorporated into our fair value
calculations subsequent to adoption.
Pursuant to FASB Financial Staff Position
157-2, the
FASB issued a partial deferral, ending on December 31,
2008, of the implementation of SFAS 157 as it relates to
all non-financial assets and liabilities where fair value is the
required measurement attribute by other accounting standards.
While we have adopted SFAS 157 for all financial assets and
liabilities effective January 1, 2008, we are in the
process of assessing the impact that the adoption of
SFAS 157 will have on our non-financial assets and
liabilities, but do not expect a material impact on our
consolidated results of operations, cash flows or financial
positions upon adoption.
FASB FSP
No. 157-3
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active, or
FSP 157-3 In
October 2008, the FASB issued
FSP 157-3,
which provides guidance in situations where a) observable
inputs do not exist, b) observable inputs exist but only in
an inactive market and c) how market quotes should be
considered when assessing the relevance of observable and
unobservable inputs to determine fair value.
FSP 157-3
was effective upon issuance, including prior periods for which
financial statements have not been issued. We believe that the
financial assets that are reflected in our financial statements
are transacted within active markets, and therefore, there is no
effect on our consolidated results of operations, cash flows or
financial positions as a result of the adoption of this FSP.
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4.
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Agreements
and Transactions with Affiliates
|
The employees supporting our operations are employees of
Midstream. Costs incurred by Midstream on our behalf for
salaries and benefits of operating personnel, as well as capital
expenditures, maintenance and repair costs, and taxes have been
directly allocated to us. Midstream also provides centralized
corporate functions on our behalf, including legal, accounting,
cash management, insurance administration and claims processing,
risk management, health, safety and environmental, information
technology, human resources, credit, payroll, internal audit,
taxes and engineering. Midstream records the accrued liabilities
and prepaid expenses for most general and administrative
expenses in its financial statements, including liabilities
related to payroll, short and long-term incentive plans,
employee retirement and medical plans, paid time off, audit,
tax, insurance and other service fees. Through June 30,
2007, our share of those costs were allocated based on
Midstreams proportionate investment (consisting of
property, plant and equipment, equity method investment and
intangibles) compared to our investment. In managements
estimation, the allocation methodologies used through
June 30, 2007 were reasonable and resulted in an allocation
to us of our costs of doing business borne by Midstream.
Effective July 1, 2007, as part of the agreement with
Midstream, we are required to reimburse Midstream for salaries
of operating personnel and employee benefits as well as capital
expenditures, maintenance and repair costs, insurance, taxes and
other direct, indirect, and allocable costs and expenses
incurred by Midstream on our behalf. We also pay Midstream an
annual fee for centralized corporate functions performed by
Midstream on our behalf, including legal, accounting, cash
management, insurance administration and claims
204
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll,
internal audit, taxes and engineering. The agreement states that
the fee for 2007 shall be $4.0 million as prorated from
July 1 through December 31, 2007. For 2008, the fee was
$8.3 million as adjusted for changes in the Consumer Price
Index. After 2008, the fee shall be mutually agreed upon.
Prior to July 1, 2007, we had no cash balances on the
consolidated balances sheets. Up to that date, all of our cash
management activity was performed by Midstream on our behalf,
including collection of receivables, payment of payables, and
the settlement of sales and purchases transactions with
Midstream, which were recorded as parent advances and were
included in parent equity on the accompanying consolidated
balance sheets.
We currently, and anticipate to continue to, sell to Midstream,
and purchase from and sell to ConocoPhillips, in the ordinary
course of business. Midstream was a significant customer during
the years ended December 31, 2008, 2007, and 2006.
Prior to December 31, 2006, we sold to and purchased from
Duke Energy Corporation. On January 2, 2007, Duke Energy
Corporation spun off their natural gas businesses, including
their 50% ownership interest in Midstream, to Duke Energy
shareholders. As a result of this transaction, Duke Energy
Corporations 50% ownership interest in Midstream was
transferred to Spectra Energy Corp. Consequently, Duke Energy
Corporation is not considered a related party for reporting
periods after January 2, 2007. We had no significant
transactions with Spectra Energy Corp.
The following table summarizes transactions with affiliates:
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Year Ended December 31,
|
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2008
|
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2007
|
|
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2006
|
|
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|
(Millions)
|
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|
DCP Midstream, LLC:
|
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|
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Sales of natural gas, NGLs and condensate
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$
|
284.4
|
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|
$
|
263.2
|
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$
|
276.3
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Losses from non-trading derivative activity
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$
|
0.6
|
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|
$
|
0.1
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|
$
|
1.1
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General and administrative expense
|
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$
|
8.5
|
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|
$
|
10.3
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|
$
|
11.3
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Duke Energy Corporation:
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Sales of natural gas, NGLs and condensate
|
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$
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|
|
|
$
|
|
|
|
$
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6.6
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Purchases of natural gas and NGLs
|
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$
|
|
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|
$
|
|
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$
|
0.1
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ConocoPhillips:
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Sales of natural gas, NGLs and condensate
|
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$
|
29.3
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|
$
|
7.7
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|
$
|
3.7
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Transportation and processing services
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$
|
0.2
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|
$
|
0.1
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|
$
|
0.3
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Purchases of natural gas and NGLs
|
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$
|
0.1
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$
|
1.1
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$
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9.2
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We had accounts receivable and accounts payable with affiliates
as follows:
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December 31,
|
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2008
|
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2007
|
|
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(Millions)
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DCP Midstream LLC:
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|
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|
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Accounts receivable
|
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$
|
20.6
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$
|
64.5
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Accounts payable
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$
|
2.4
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$
|
1.5
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ConocoPhillips:
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Accounts receivable
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$
|
0.1
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$
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205
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Capital
Project Reimbursement
In addition, Midstream has reimbursed us for work we performed
on certain capital projects as defined in the Contribution
Agreement. We received $2.3 million and $3.4 million
of capital reimbursements during the years ended
December 31, 2008 and 2007, respectively. These
reimbursements are treated as contributions from Midstream.
Competition
Neither Midstream or Partners, nor any of their respective
affiliates are restricted under the limited liability agreement
from competing with us in other business opportunities,
transactions, ventures, or other arrangements that may be
competitive with or the same as us.
Indemnification
Effective upon closing on July 1, 2007, Midstream agreed to
indemnify us until July 1, 2009 for any claims for fines or
penalties of any governmental authority for periods prior to the
closing and that are associated with assets that were formerly
owned by Gulf South and UP Fuels, and agreed to indemnify us
indefinitely for breaches of the agreement and certain existing
claims. The indemnity obligation for breach of the
representations and warranties is not effective until claims
exceed in the aggregate $2.7 million and is subject to a
maximum liability of $27.0 million. This indemnity
obligation for all other claims other than a breach of the
representations and warranties does not become effective until
an individual claim or series of related claims exceed $50,000.
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5.
|
Property,
Plant and Equipment
|
A summary of property, plant and equipment is as follows:
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Depreciable
|
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December 31,
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|
Life
|
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2008
|
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|
2007
|
|
|
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(Millions)
|
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|
Gathering systems
|
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15 30 Years
|
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|
$
|
92.8
|
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|
$
|
78.9
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|
Processing plants
|
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|
25 30 Years
|
|
|
|
219.8
|
|
|
|
218.5
|
|
Transportation
|
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25 30 Years
|
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|
42.6
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40.0
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Underground storage
|
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20 50 Years
|
|
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|
0.1
|
|
|
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General plant
|
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3 5 Years
|
|
|
|
7.9
|
|
|
|
7.8
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Construction work in progress
|
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|
|
|
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30.3
|
|
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14.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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393.5
|
|
|
|
359.9
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|
Accumulated depreciation
|
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|
|
|
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(140.1
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)
|
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|
(123.4
|
)
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Property, plant and equipment, net
|
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|
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$
|
253.4
|
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$
|
236.5
|
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Depreciation expense for the years ended December 31, 2008,
2007 and 2006, was $16.7 million, $15.8 million and
$14.6 million respectively. At December 31, 2008, we
had non-cancelable purchase obligations of approximately
$0.8 million for capital projects anticipated to be
completed in 2009.
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6.
|
Risk
Management and Derivative Activities, Credit Risk and Financial
Instruments
|
The only impact of our derivative activity was losses from
non-trading derivative activity affiliates of
$0.6 million, $0.1 million and $1.1 million for
the years ended December 31, 2008, 2007 and 2006,
respectively.
206
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We are exposed to market risks, including changes in commodity
prices. We may use financial instruments such as forward
contracts, swaps and futures to mitigate the effects of the
identified risks. In general, we attempt to mitigate risks
related to the variability of future cash flows resulting from
changes in applicable commodity prices. Midstream has a
comprehensive risk management policy, or the Risk Management
Policy, and a risk management committee, to monitor and manage
market risks associated with commodity prices. Midstreams
Risk Management Policy prohibits the use of derivative
instruments for speculative purposes.
Commodity Price Risk Our
principal operations of gathering, processing, and transporting
natural gas, and the accompanying operations of transporting and
sale of NGLs create commodity price risk due to market
fluctuations in commodity prices, primarily with respect to the
prices of NGLs and natural gas. As an owner and operator of
natural gas processing assets, we have an inherent exposure to
market variables and commodity price risk. The amount and type
of price risk is dependent on the underlying natural gas
contracts to purchase and process raw natural gas. Risk is also
dependent on the types and mechanisms for sales of natural gas,
NGLs and condensate, and related products produced, processed or
transported.
Credit Risk We sell natural gas
to marketing affiliates of natural gas pipelines, marketing
affiliates of integrated oil companies, marketing affiliates of
Midstream, national wholesale marketers, industrial end-users
and gas-fired power plants. Our principal NGL customers include
an affiliate of Midstream, producers and marketing companies.
Concentration of credit risk may affect our overall credit risk,
in that these customers may be similarly affected by changes in
economic, regulatory or other factors. Where exposed to credit
risk, we analyze the counterparties financial condition
prior to entering into an agreement, establish credit limits,
and monitor the appropriateness of these limits on an ongoing
basis. We operate under Midstreams corporate credit
policy. Midstreams corporate credit policy, as well as the
standard terms and conditions of our agreements, prescribe the
use of financial responsibility and reasonable grounds for
adequate assurances. These provisions allow Midstreams
credit department to request that a counterparty remedy credit
limit violations by posting cash or letters of credit for
exposure in excess of an established credit line. The credit
line represents an open credit limit, determined in accordance
with Midstreams credit policy and guidelines. The
agreements also provide that the inability of counterparty to
post collateral is sufficient cause to terminate a contract and
liquidate all positions. The adequate assurance provisions also
allow us to suspend deliveries, cancel agreements or continue
deliveries to the buyer after the buyer provides security for
payment to us in a form satisfactory to us.
Commodity Non-Trading Derivative
Activity The sale of energy related
products and services exposes us to the fluctuations in the
market values of exchanged instruments. On a monthly basis, we
may enter into non-trading derivative instruments in order to
match the pricing terms to manage our purchase and sale
portfolios. Midstream manages our marketing portfolios in
accordance with their Risk Management Policy, which limits
exposure to market risk.
Normal Purchases and Normal
Sales If a contract qualifies and is
designated as a normal purchase or normal sale, no recognition
of the contracts fair value in the consolidated financial
statements is required until the associated delivery period
impacts earnings. We have applied this accounting election for
contracts involving the purchase or sale of physical natural gas
or NGLs in future periods.
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7.
|
Asset
Retirement Obligations
|
Our asset retirement obligations relate primarily to the
retirement of various gathering pipelines and processing
facilities, obligations related to
right-of-way
easement agreements, and contractual leases for land use. We
recognize the fair value of a liability for an asset retirement
obligation in the period in which it is incurred, if a
reasonable estimate of fair value can be made. The fair value of
the liability is added to the carrying amount of the associated
asset. This additional carrying amount is then depreciated over
the life of the asset. The liability increases due to the
passage of time based on the time value of money until the
207
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
obligation is settled. Accretion expense for the years ended
December 31, 2008, 2007 and 2006 was not significant.
The asset retirement obligation is adjusted each quarter for any
liabilities incurred or settled during the period, accretion
expense and any revisions made to the estimated cash flows. The
asset retirement obligation as December 31, 2008 and 2007
included in the consolidated balance sheets as other long-term
liabilities was $0.6 million and $0.5 million,
respectively.
In May 2006, the State of Texas enacted a margin-based franchise
tax law that replaced the existing franchise tax, commonly
referred to as the Texas margin tax. The Texas margin tax is
assessed at 1% of taxable margin apportioned to Texas. As a
result of the change in Texas franchise law, our status in the
state of Texas changed from non-taxable to taxable. Since the
Texas margin tax is considered an income tax, in 2006 we
recorded a non-current deferred tax liability of
$1.8 million. The Texas margin tax became effective for
franchise tax reports due on or after January 1, 2008. The
2008 tax was based on revenues earned during the 2007 fiscal
year. Accordingly, we recorded current tax expense for the Texas
margin tax for 2008 and 2007 of $0.6 million and
$0.8 million, respectively, and a reduction in deferred
taxes of $0.1 million for both 2008 and 2007.
Our effective tax rate differs from statutory rates primarily
due to our being treated as a pass-through entity for United
States income tax purposes, while being treated as a taxable
entity in Texas.
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9.
|
Commitments
and Contingent Liabilities
|
Litigation We are not a party to
any significant legal proceedings, but are a party to various
administrative and regulatory proceedings and commercial
disputes that have arisen in the ordinary course of our
business. Management currently believes that the ultimate
resolution of the foregoing matters, taken as a whole, and after
consideration of amounts accrued, insurance coverage or other
indemnification arrangements, will not have a material adverse
effect upon our consolidated results of operations, financial
position, or cash flows.
Insurance For the period August
2006 through August 2007, Midstreams insurance coverage
was carried with an affiliate of ConocoPhillips and third party
insurers. Prior to August 2006, Midstream carried a portion of
their insurance coverage with an affiliate of Duke Energy
Corporation. Effective in August 2007, insurance coverage is
carried with third party insurers. Midstreams insurance
coverage includes: (1) commercial general public liability
insurance for liabilities arising to third parties for bodily
injury and property damage resulting from operations;
(2) workers compensation liability coverage to
required statutory limits; (3) automobile liability
insurance for all owned, non-owned and hired vehicles covering
liabilities to third parties for bodily injury and property
damage; (4) excess liability insurance above the
established primary limits for commercial general liability and
automobile liability insurance; and (5) property insurance
covering the replacement value of all real and personal property
damage, including damages arising from boiler and machinery
breakdowns, windstorms, earthquake, flood damage and business
interruption/extra expense. All coverages are subject to certain
limits and deductibles, the terms and conditions of which are
common for companies with similar types of operations.
A portion of the insurance costs described above are allocated
by Midstream to us through the allocation methodology described
in Note 4.
Environmental The operation of
pipelines, plants and other facilities for gathering,
transporting, processing, or treating natural gas, NGLs and
other products is subject to stringent and complex laws and
regulations pertaining to health, safety and the environment. As
an owner or operator of these facilities, we must comply with
United States laws and regulations at the federal, state and
local levels that relate to air and
208
DCP EAST
TEXAS HOLDINGS, LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
water quality, hazardous and solid waste management and
disposal, and other environmental matters. The cost of planning,
designing, constructing and operating pipelines, plants, and
other facilities must incorporate compliance with environmental
laws and regulations and safety standards. Failure to comply
with these laws and regulations may trigger a variety of
administrative, civil and potentially criminal enforcement
measures, including citizen suits, which can include the
assessment of monetary penalties, the imposition of remedial
requirements, and the issuance of injunctions or restrictions on
operation. Management believes that, based on currently known
information, compliance with these laws and regulations will not
have a material adverse effect on our consolidated results of
operations, financial position or cash flows.
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10.
|
Supplemental
Cash Flow Information
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash additions of property, plant and equipment
|
|
$
|
2.0
|
|
|
$
|
0.9
|
|
|
$
|
3.1
|
|
Accrued contributions related to reimbursements
|
|
$
|
|
|
|
$
|
0.2
|
|
|
$
|
|
|
In February 2009, we announced that our East Texas natural gas
processing complex and residue natural gas delivery system known
as the Carthage Hub, have been temporarily shut in following a
fire that was caused by a third party underground pipeline
outside of our property line that ruptured. No employees or
contractors were injured in the incident. There was no
significant damage to the natural gas processing complex. As of
February 25, 2009, the complex began processing through one
of the five plants, and it is expected that full processing
capacities will be restored for the entire complex over the next
30 days. Residue gas will be redelivered into limited
available pipeline interconnects while the Carthage Hub
undergoes inspection and repairs.
In February 2009, Midstream entered into an agreement to
contribute an additional 25.1% interest in East Texas to
Partners in exchange for 3.5 million Class D units.
This transaction is expected to close in April 2009. Subsequent
to this transaction, Partners will consolidate East Texas in
their consolidated financial statements.
209
DCP EAST
TEXAS HOLDINGS, LLC
SCHEDULE II
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND
RESERVES
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|
|
|
|
|
|
|
|
Charged to
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Consolidated
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning of
|
|
|
Statements of
|
|
|
Deductions/
|
|
|
End of
|
|
|
|
Period
|
|
|
Operations
|
|
|
Other
|
|
|
Period
|
|
|
|
(Millions)
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
0.5
|
|
|
$
|
(0.1
|
)
|
|
$
|
|
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
0.2
|
|
|
$
|
0.3
|
|
|
$
|
|
|
|
$
|
0.5
|
|
Environmental
|
|
|
0.3
|
|
|
|
|
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.5
|
|
|
$
|
0.3
|
|
|
$
|
(0.3
|
)
|
|
$
|
0.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
0.1
|
|
|
$
|
0.1
|
|
|
$
|
|
|
|
$
|
0.2
|
|
Environmental
|
|
|
0.4
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.5
|
|
|
$
|
0.1
|
|
|
$
|
(0.1
|
)
|
|
$
|
0.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210
A list of exhibits required by Item 601 of
Regulation S-K
to be filed as part of this report:
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Amendment No. 1 to Amended and Restated Limited Liability
Company Agreement of DCP Midstream GP, LLC dated as of
January 20, 2009 and Amended and Restated Limited Liability
Company Agreement of DCP Midstream GP, LLC dated
December 7, 2005.
|
|
10
|
.1*
|
|
Purchase and Sale Agreement, dated March 7, 2007, between
Anadarko Gathering Company, Anadarko Energy Services Company and
DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP
Midstream Partners, LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.2*
|
|
Bridge Credit Agreement, dated May 9, 2007 among DCP
Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia
Bank, National Association (attached as Exhibit 99.2 to DCP
Midstream Partners, LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.3*
|
|
Third Amendment to Omnibus Agreement, dated May 9, 2007,
among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 99.3 to DCP Midstream
Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.4*
|
|
First Amendment to Credit Agreement, dated May 9, 2007,
among DCP Midstream Operating, LP, DCP Midstream Partners, LP
and Wachovia Bank, National Association (attached as
Exhibit 99.4 to DCP Midstream Partners LPs current
report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.5*
|
|
Contribution and Sale Agreement, dated May 21, 2007,
between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC
and DCP Midstream Partners, LP (attached as Exhibit 10.1 to
DCP Midstream Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.6*
|
|
Common Unit Purchase Agreement, dated May 21, 2007, by and
among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.7*
|
|
Contribution Agreement, dated May 23, 2007, among DCP LP
Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCP
Midstream Partners, LP (attached as Exhibit 10.1 to DCP
Midstream Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.8*
|
|
Common Unit Purchase Agreement, dated June 19, 2007, by and
among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 25, 2007).
|
|
10
|
.9*
|
|
Registration Rights Agreement, dated June 22, 2007, by and
among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.2 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 25, 2007).
|
|
10
|
.10*
|
|
Amended and Restated Credit Agreement, dated June 21, 2007,
among DCP Midstream Operating, LP, DCP Midstream Partners, LP
and Wachovia Bank, National Association as Administrative Agent
(attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 27, 2007).
|
|
10
|
.11*
|
|
Fourth Amendment to Omnibus Agreement, dated July 1, 2007,
by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP
Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.2 to DCP Midstream
Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on July 2, 2007).
|
|
10
|
.12*
|
|
Amended and Restated Limited Liability Company Agreement of DCP
East Texas Holdings, LLC, dated July 1, 2007, between DCP
Midstream, LLC and DCP Assets Holding, LP (attached as
Exhibit 10.3 to DCP Midstream Partners LPs current
report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on July 2, 2007).
|
|
10
|
.13*
|
|
Fifth Amendment to Omnibus Agreement dated August 7, 2007,
among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream
Partners, LP
Form 10-Q
(File
No. 001-32678)
filed with the Securities and Exchange Commission on
August 9, 2007).
|
211
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.14*
|
|
Sixth Amendment to Omnibus Agreement, dated August 29,
2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream
Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on September 5, 2007).
|
|
10
|
.15*
|
|
Registration Rights Agreement, dated August 29, 2007, by
and among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.2 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on September 5, 2007).
|
|
10
|
.16
|
|
Contribution Agreement dated February 24, 2009, among DCP
Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP,
LP and DCP Midstream, LLC.
|
|
12
|
.1
|
|
Ratio of Earnings to Fixed Charges.
|
|
21
|
.1
|
|
List of Subsidiaries of DCP Midstream Partners, LP.
|
|
23
|
.1
|
|
Consent of Deloitte & Touche LLP on Consolidated
Financial Statements and Financial Statement Schedule of DCP
Midstream Partners, LP and the effectiveness of DCP Midstream
Partners, LPs internal control over financial reporting.
|
|
23
|
.2
|
|
Consent of Ernst & Young LLP on Consolidated Financial
Statements of Discovery Producer Services LLC.
|
|
23
|
.3
|
|
Consent of Deloitte & Touche LLP on Consolidated
Financial Statements of DCP East Texas Holdings, LLC.
|
|
23
|
.4
|
|
Consent of Deloitte & Touche LLP on Consolidated
Balance Sheet of DCP Midstream GP, LP.
|
|
23
|
.5
|
|
Consent of Deloitte & Touche LLP on Consolidated
Balance Sheet of DCP Midstream, LLC.
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99
|
.1
|
|
Consolidated Balance Sheet of DCP Midstream GP, LP as of
December 31, 2008.
|
|
99
|
.2
|
|
Consolidated Balance Sheet of DCP Midstream, LLC as of
December 31, 2008.
|
|
|
|
* |
|
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
212
SIGNATURES
Pursuant to the requirements of the Section 13 or 15(d) of
the Securities Exchange Act of 1934, the Registrant has duly
caused this Report to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Denver,
State of Colorado, on March 5, 2009.
DCP Midstream Partners, LP
|
|
|
|
By:
|
/s/ DCP
Midstream GP, LP
|
its General Partner
|
|
|
|
By:
|
/s/ DCP
Midstream GP, LLC
|
its General Partner
Name: Mark A. Borer
|
|
|
|
Title:
|
President and Chief Executive Officer
|
213
POWER OF
ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS that each person whose
signature appears below constitutes and appoints each of Mark A.
Borer and Angela A. Minas as
his/her true
and lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him or in his name, place,
and stead, in any and all capacities, to sign any and all
amendments (including post-effective amendments) to this annual
report, and to file the same, with all exhibits thereto, and
other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorney-in-fact and
agent full power and authority to do and perform each and every
act and thing requisite and necessary to be done in connection
therewith, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that
said attorney-in-fact and agent or their or his substitute or
substitutes, may lawfully do or cause to be done by virtue
hereof.
Pursuant to the requirements of the Securities Exchange Act of
1934, this Report has been signed below by the following persons
on behalf of the Registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Mark
A. Borer
Mark
A. Borer
|
|
President, Chief Executive Officer and Director (Principal
Executive Officer)
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Angela
A. Minas
Angela
A. Minas
|
|
Vice President and Chief Financial Officer (Principal Financial
Officer)
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Scott
R. Delmoro
Scott
R. Delmoro
|
|
Chief Accounting Officer (Principal Accounting Officer)
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Thomas
C. OConnor
Thomas
C. OConnor
|
|
Chairman of the Board and Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Paul
F. Ferguson, Jr.
Paul
F. Ferguson, Jr.
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Gregory
J. Goff
Gregory
J. Goff
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Alan
N. Harris
Alan
N. Harris
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ John
E. Lowe
John
E. Lowe
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Frank
A. McPherson
Frank
A. McPherson
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Thomas
C. Morris
Thomas
C. Morris
|
|
Director
|
|
March 5, 2009
|
|
|
|
|
|
/s/ Stephen
R. Springer
Stephen
R. Springer
|
|
Director
|
|
March 5, 2009
|
214
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Amendment No. 1 to Amended and Restated Limited Liability
Company Agreement of DCP Midstream GP, LLC dated as of
January 20, 2009 and Amended and Restated Limited Liability
Company Agreement of DCP Midstream GP, LLC dated
December 7, 2005.
|
|
10
|
.1*
|
|
Purchase and Sale Agreement, dated March 7, 2007, between
Anadarko Gathering Company, Anadarko Energy Services Company and
DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP
Midstream Partners, LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.2*
|
|
Bridge Credit Agreement, dated May 9, 2007 among DCP
Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia
Bank, National Association (attached as Exhibit 99.2 to DCP
Midstream Partners, LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.3*
|
|
Contribution and Sale Agreement, dated May 9, 2007, among
DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream
GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP
(attached as Exhibit 99.3 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.4*
|
|
First Amendment to Credit Agreement, dated May 9, 2007,
among DCP Midstream Operating, LP, DCP Midstream Partners, LP
and Wachovia Bank, National Association (attached as
Exhibit 99.4 to DCP Midstream Partners LPs current
report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 14, 2007).
|
|
10
|
.5*
|
|
Contribution Agreement, dated May 21, 2007, among DCP LP
Holdings, LP, DCP Midstream, LLC and DCP Midstream Partners, LP
(attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.6*
|
|
Common Unit Purchase Agreement, dated May 21, 2007, by and
among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.7*
|
|
Contribution Agreement, dated May 23, 2007, among DCP
Midstream Partners, LP (attached as Exhibit 10.1 to DCP
Midstream Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on May 25, 2007).
|
|
10
|
.8*
|
|
Common Unit Purchase Agreement, dated June 19, 2007, among
DCP Midstream Partners, LP and the Purchasers listed therein
(attached as Exhibit 10.1 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 25, 2007).
|
|
10
|
.9*
|
|
Registration Rights Agreement, dated June 22, 2007, by and
among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.2 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 25, 2007).
|
|
10
|
.10*
|
|
Amended and Restated Credit Agreement, dated July 1, 2007,
among DCP Midstream, LLC and Wachovia Bank, National Association
as Administrative Agent (attached as Exhibit 10.1 to DCP
Midstream Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on June 27, 2007).
|
|
10
|
.11*
|
|
Fourth Amendment to Omnibus Agreement, dated July 1, 2007,
by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP
Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.2 to DCP Midstream
Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on July 2, 2007).
|
|
10
|
.12*
|
|
Amended and Restated Limited Liability Company Agreement of DCP
East Texas Holdings, LLC, dated July 1, 2007, between DCP
Midstream, LLC and DCP Assets Holding, LP (attached as
Exhibit 10.3 to DCP Midstream Partners LPs current
report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on July 2, 2007).
|
|
10
|
.13*
|
|
Fifth Amendment to Omnibus Agreement dated August 7, 2007,
among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream
Partners, LP
Form 10-Q
(File
No. 001-32678)
filed with the Securities and Exchange Commission on
August 9, 2007).
|
215
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.14*
|
|
Sixth Amendment to Omnibus Agreement, dated August 29,
2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream
Partners LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on September 5, 2007).
|
|
10
|
.15*
|
|
Registration Rights Agreement, dated August 29, 2007, by
and among DCP Midstream Partners, LP and the Purchasers listed
therein (attached as Exhibit 10.2 to DCP Midstream Partners
LPs current report on
Form 8-K
(File
No. 001-32678)
filed with the SEC on September 5, 2007).
|
|
10
|
.16
|
|
Contribution Agreement dated February 24, 2009, among DCP
Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP,
LP and DCP Midstream, LLC.
|
|
12
|
.1
|
|
Ratio of Earnings to Fixed Charges.
|
|
21
|
.1
|
|
List of Subsidiaries of DCP Midstream Partners, LP.
|
|
23
|
.1
|
|
Consent of Deloitte & Touche LLP on Consolidated
Financial Statements and Financial Statement Schedule of DCP
Midstream Partners, LP and the effectiveness of DCP Midstream
Partners, LPs internal control over financial reporting.
|
|
23
|
.2
|
|
Consent of Ernst & Young LLP on Consolidated Financial
Statements of Discovery Producer Services LLC.
|
|
23
|
.3
|
|
Consent of Deloitte & Touche LLP on Consolidated
Financial Statements of DCP East Texas Holdings, LLC.
|
|
23
|
.4
|
|
Consent of Deloitte & Touche LLP on Consolidated
Balance Sheet of DCP Midstream GP, LP.
|
|
23
|
.5
|
|
Consent of Deloitte & Touche LLP on Consolidated
Balance Sheet of DCP Midstream, LLC.
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99
|
.1
|
|
Consolidated Balance Sheet of DCP Midstream GP, LP as of
December 31, 2008.
|
|
99
|
.2
|
|
Consolidated Balance Sheet of DCP Midstream, LLC as of
December 31, 2008.
|
|
|
|
* |
|
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
216
exv3w1
Exhibit 3.1
AMENDMENT NO. 1 TO
AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT
OF
DCP MIDSTREAM GP, LLC
This Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement (the LLC
Agreement) of DCP Midstream GP, LLC (the Company) is hereby adopted, executed and agreed to by
DCP Midstream, LLC as Sole Member (Sole Member) of the Company.
WHEREAS, the Sole Member desires to amend the LLC Agreement by revising Section 6.02(e)(ii) of
the LLC Agreement.
NOW, THEREFORE BE IT RESOLVED, that the Sole Member does hereby amend the LLC Agreement as
follows:
Section 6.02(e)(ii) is hereby amended by deleting the last four words thereof and replacing it
with the following:
In addition to any other committees established by the Board of Directors pursuant to Section
6.02(e)(i), the Board of Directors shall maintain a Conflicts Committee, which shall be composed
of at least one Independent Director. The Conflicts Committee shall be responsible for
(A) approving or disapproving, as the case may be, any matters regarding the business and affairs
of the Company, DCP GP or the MLP considered by, or submitted to, such Conflicts Committee at the
request of the Board of Directors pursuant to the terms of the DCP GP Agreement or the MLP
Partnership Agreement, (B) approving any material amendments to the Omnibus Agreement,
(C) approving or disapproving, as the case may be, the entering into of any material transaction
with a Member or any Affiliate of a Member, other than transactions in the ordinary course of
business to the extent that the Board of Directors requests the Conflicts Committee to make such
determination, (D) amending (1) Section 2.07, (2) the definitions of Independent Director
in Section 6.02(a) or (3) this Section 6.02(e)(ii), and (E) performing such other functions as the
Board may assign from time to time or as may be specified in a written charter of the Conflicts
Committee. In acting or otherwise voting on the matters referred to in this Section 6.02(e)(ii),
to the fullest extent permitted by law, including Section 18-1101(c) of the Delaware Act and
Section 17-1101(c) of the Delaware Revised Uniform Limited Partnership Act, as amended from time to
time, the Directors constituting the Conflicts Committee shall consider only the interest of the
MLP.
IN WITNESS WHEREOF, the Sole Member has executed this Amendment No. 1 as of January 20, 2009.
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DCP Midstream, LLC |
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By:
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/s/ Brent L. Backes |
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Name: Brent L. Backes
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Title: Group Vice President, General
Counsel and Corporate Secretary |
EXECUTION COPY
AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
DCP MIDSTREAM GP, LLC
A Delaware Limited Liability Company
AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
DCP MIDSTREAM GP, LLC
A Delaware Limited Liability Company
TABLE OF CONTENTS
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ARTICLE 1 |
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DEFINITIONS |
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1.01
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Definitions
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1.02
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Construction
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ARTICLE 2 |
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ORGANIZATION |
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2.01
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Formation
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2.02
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Name
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2.03
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Registered Office; Registered Agent; Principal Office;
Other Offices
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2.04
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Purpose
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2.05
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Term
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2.06
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No State-Law Partnership; Withdrawal
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2.07
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Certain Undertakings Relating to Separateness
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ARTICLE 3 |
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MATTERS RELATING TO MEMBERS |
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3.01
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Members
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3.02
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Creation of Additional Membership Interest
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3.03
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Liability to Third Parties
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ARTICLE 4 |
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CAPITAL CONTRIBUTIONS |
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4.01
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Capital Contributions
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4.02
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Loans
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4.03
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Return of Contributions
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ARTICLE 5 |
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DISTRIBUTIONS |
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5.01
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Distributions
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ARTICLE 6 |
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MANAGEMENT |
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6.01
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Management
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6.02
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Board of Directors
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6.03
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Officers
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6.04
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Duties of Officers and Directors
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6.05
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Compensation
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6.06
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Indemnification
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6.07
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Liability of Indemnitees
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6.08
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Outside Activities
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6.09
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Resolution of Conflicts of Interest; Standard of
Conduct and Modification of Duties
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ARTICLE 7 |
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TAX MATTERS |
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7.01
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Tax Returns and Tax Characterization
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ARTICLE 8 |
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BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS |
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8.01
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Maintenance of Books
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8.02
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Reports
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8.03
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Bank Accounts
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ARTICLE 9 |
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DISSOLUTION, WINDING-UP AND TERMINATION |
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9.01
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Dissolution
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9.02
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Winding-Up and Termination
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ARTICLE 10 |
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MERGER, CONSOLIDATION OR CONVERSION |
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10.01
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Authority
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10.02
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Procedure for Merger, Consolidation or Conversion
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10.03
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Approval by Members of Merger or Consolidation
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10.04
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Certificate of Merger, Consolidation or Conversion
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ARTICLE 11 |
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GENERAL PROVISIONS |
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11.01
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Notices
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11.02
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Entire Agreement; Supersedure
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11.03
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Effect of Waiver or Consent
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11.04
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Amendment or Restatement
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11.05
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Binding Effect
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11.06
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Governing Law; Severability
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11.07
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Further Assurances
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11.08
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Offset
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11.09
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Counterparts
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ii
AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
DCP Midstream GP, LLC
A Delaware Limited Liability Company
THIS AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT (this Agreement) of DCP
Midstream GP, LLC, a Delaware limited liability company (the Company), executed on December 7,
2005 (the Effective Date), is adopted, executed and agreed to, by Duke Energy Field Services,
LLC, a Delaware limited liability company (DEFS), as the sole Member of the Company.
RECITALS
A. DEFS formed the Company on August 5, 2005 as the sole member.
B. The Limited Liability Company Agreement of DCP Midstream GP, LLC was executed effective
August 5, 2005 (the Existing Agreement).
C. DEFS, the sole Member of the Company, deems it advisable to amend and restate the limited
liability company agreement of the Company in its entirety as set forth herein.
AGREEMENTS
For and in consideration of the premises, the covenants and agreements set forth herein and
other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged,
DEFS, as the sole Member of the Company, hereby amends and restates the Existing Agreement in its
entirety as follows:
ARTICLE 1
DEFINITIONS
1.01 Definitions. Each capitalized term used herein shall have the meaning given such term in Attachment I.
1.02 Construction. Unless the context requires otherwise: (a) the gender (or lack of gender) of all words used in
this Agreement includes the masculine, feminine and neuter; (b) references to Articles and Sections
refer to Articles and Sections of this Agreement; (c) references to Laws refer to such Laws as they
may be amended from time to time, and references to particular provisions of a Law include any
corresponding provisions of any succeeding Law; (d) references to money refer to legal currency of
the United States of America; (e) including means including without limitation and is a term of
illustration and not of limitation; (f) all definitions set forth herein shall be deemed applicable
whether the words defined are used herein in the singular or the plural; and (g) neither this
Agreement nor any other agreement, document or instrument referred to herein or executed and delivered
in connection herewith shall be construed against any Person as the principal draftsperson hereof or thereof.
ARTICLE 2
ORGANIZATION
2.01 Formation. The Company was organized as a Delaware limited liability company by the filing of a Certificate
of Formation (Organizational Certificate) on August 5, 2005 with the Secretary of State of the
State of Delaware under and pursuant to the Delaware Act.
2.02 Name. The name of the Company is DCP Midstream GP, LLC and all Company business must be conducted in
that name or such other names that comply with Law as the Board of Directors may select.
2.03 Registered Office; Registered Agent; Principal Office; Other Offices. The registered office of the Company required by the Delaware Act to be maintained in the State
of Delaware shall be the office of the initial registered agent for service of process named in the
Organizational Certificate or such other office (which need not be a place of business of the
Company) as the Board of Directors may designate in the manner provided by Law. The registered
agent for service of process of the Company in the State of Delaware shall be the initial
registered agent for service of process named in the Organizational Certificate or such other
Person or Persons as the Board of Directors may designate in the manner provided by Law. The
principal office of the Company in the United States shall be at such a place as the Board of
Directors may from time to time designate, which need not be in the State of Delaware, and the
Company shall maintain records there and shall keep the street address of such principal office at
the registered office of the Company in the State of Delaware. The Company may have such other
offices as the Board of Directors may designate.
2.04 Purpose. The purposes of the Company are the transaction of any or all lawful business for which limited
liability companies may be organized under the Delaware Act.
2.05 Term. The period of existence of the Company commenced on August 5, 2005 and shall end at such time as
a certificate of cancellation is filed in accordance with Section 9.02(c).
2.06 No State-Law Partnership; Withdrawal. It is the intent that the Company shall be a limited liability company formed under the Laws of
the State of Delaware and shall not be a partnership (including a limited partnership) or joint
venture, and that the Members not be a partner or joint venturer of any other party for any
purposes other than federal and state tax purposes, and this Agreement may not be construed to
suggest otherwise. A Member does not have the right to Withdraw from the Company; provided,
however, that a Member shall have the power to Withdraw at any time in violation of this Agreement.
If a Member exercises such power in violation of this Agreement, (a) such Member shall be liable
to the Company and its Affiliates for all monetary damages suffered by them as a result of such
Withdrawal; and (b) such Member shall not have any rights under Section 18.604 of the Delaware Act.
In no event shall the Company have the right, through specific performance or otherwise, to
prevent a Member from Withdrawing in violation of this Agreement.
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2.07 Certain Undertakings Relating to Separateness.
(a) Separateness Generally. The Company shall, and shall cause DCP GP to, conduct
their respective businesses and operations in accordance with this Section 2.07.
(b) Separate Records. The Company shall, and shall cause DCP GP to, (i) maintain
their respective books and records and their respective accounts separate from those of any other
Person, (ii) maintain their respective financial records, which will be used by them in their
ordinary course of business, showing their respective assets and liabilities separate and apart
from those of any other Person, except their consolidated Subsidiaries, (iii) not have their
respective assets and/or liabilities included in a consolidated financial statement of any
Affiliate of the Company unless appropriate notation shall be made on such Affiliates consolidated
financial statements to indicate the separateness of the Company and DCP GP and their assets and
liabilities from such Affiliate and the assets and liabilities of such Affiliate, and to indicate
that the assets and liabilities of the Company and DCP GP are not available to satisfy the debts
and other obligations of such Affiliate, and (iv) file their respective own tax returns separate
from those of any other Person, except (A) to the extent that the Company or DCP GP (x) is treated
as a disregarded entity for tax purposes or (y) is not otherwise required to file tax returns
under applicable law or (B) as may otherwise be required by applicable law.
(c) Separate Assets. The Company shall not commingle or pool, and shall cause DCP GP
not to commingle or pool, their respective funds or other assets with those of any other Person,
and shall maintain their respective assets in a manner that is not costly or difficult to
segregate, ascertain or otherwise identify as separate from those of any other Person.
(d) Separate Name. The Company shall, and shall cause DCP GP to, (i) conduct their
respective businesses in their respective own names, (ii) use separate stationery, invoices, and
checks, (iii) correct any known misunderstanding regarding their respective separate identities
from that of any other Person (including DEFS and its Subsidiaries other than the Company and DCP
GP), and (iv) generally hold itself out as an entity separate from any other Person (including DEFS
and its Subsidiaries other than the Company and DCP GP).
(e) Separate Credit. The Company shall, and shall cause DCP GP to, (i) pay their
respective obligations and liabilities from their respective own funds (whether on hand or
borrowed), (ii) maintain adequate capital in light of their respective business operations, (iii)
not guarantee or become obligated for the debts of any other Person, other than the Company and DCP
GP and except to the extent specified in the Contribution Agreement or the Omnibus Agreement, (iv)
not hold out their respective credit as being available to satisfy the obligations or liabilities
of any other Person except to the extent specified in the Contribution Agreement or the Omnibus
Agreement, (v) not acquire debt obligations or debt securities of DEFS or its Affiliates (other
than the Company and DCP GP), (vi) not pledge their assets for the benefit of any Person or make
loans, advances or capital contributions to DEFS or any of its Affiliates (other than the MLP and
its Subsidiaries and, with respect to the Company, other than DCP GP), or (vii) use its
commercially reasonable efforts to cause the operative documents under which DCP GP borrows money,
is an issuer of debt securities, or guarantees any such borrowing or issuance after the Effective
Date, to contain provisions to the effect that (A) the lenders
or purchasers of debt securities, respectively, acknowledge that they have advanced funds or purchased debt securities,
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respectively,
in reliance upon the separateness of the Company and DCP GP from each other and from any other
Persons (including DEFS and its Affiliates, other than the Company and DCP GP) and (B) the Company
and DCP GP have assets and liabilities that are separate from those of other persons (including
DEFS and its Affiliates, other than the Company and DCP GP); provided that the Company and DCP GP
may engage in any transaction described in clauses (v)-(vi) of this Section 2.07(e) if prior
Special Approval has been obtained for such transaction and either (A) the Conflicts Committee has
determined that the borrower or recipient of the credit support is not then insolvent and will not
be rendered insolvent as a result of such transaction or (B) in the case of transactions described
in clause (v), such transaction is completed through a public sale or a National Securities
Exchange.
(f) Separate Formalities. The Company shall, and shall cause DCP GP to, (i) observe
all limited liability company or partnership formalities and other formalities required by their
respective organizational documents, the laws of the jurisdiction of their respective formation, or
other laws, rules, regulations and orders of governmental authorities exercising jurisdiction over
it, (ii) engage in transactions with DEFS and its Affiliates (other than the Company or DCP GP) in
conformity with the requirements of Section 7.9 of the DCP GP Agreement, and (iii) subject to the
terms of the Omnibus Agreement, promptly pay, from their respective own funds and on a timely
basis, their respective allocable shares of general and administrative expenses, capital
expenditures, and costs for services performed by DEFS or Affiliates of DEFS (other than the
Company or DCP GP). Each material contract between the Company or DCP GP, on the one hand, and
DEFS or Affiliates of DEFS (other than the Company or DCP GP), on the other hand, shall be subject
to the requirements of Section 7.9 of the DCP GP Agreement, and must be (x) approved by Special
Approval or (y) on terms objectively demonstrable to be no less favorable to DCP GP than those
generally being provided to or available from unrelated third parties, and in any event must be in
writing.
(g) No Effect. Failure by the Company to comply with any of the obligations set forth
above shall not affect the status of the Company as a separate legal entity, with its separate
assets and separate liabilities or restrict or limit the Company from engaging or contracting with
DEFS and its Affiliates for the provision of services or the purchase or sale of products, whether
under the Omnibus Agreement or otherwise.
ARTICLE 3
MATTERS RELATING TO MEMBERS
3.01 Members. DEFS has previously been admitted as a Member of the Company.
3.02 Creation of Additional Membership Interest. The Company may issue additional Membership Interests in the Company pursuant to this Section
3.02. The terms of admission or issuance may provide for the creation of different classes or
groups of Members having different rights, powers, and duties. The creation of any new class or
group of Members approved as required herein may be reflected in an amendment to this Agreement
executed in accordance with Section 11.04 indicating the different rights, powers, and duties
thereof. Any such admission is effective only after the new Member has executed and delivered to
the Members an instrument containing the notice address of the new Member and the new Members
ratification of this Agreement and agreement to be bound by it.
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3.03 Liability to Third Parties. No Member or beneficial owner of any Membership Interest shall be liable for the Liabilities of
the Company.
ARTICLE 4
CAPITAL CONTRIBUTIONS
4.01 Capital Contributions.
(a) In exchange for its Membership Interest, DEFS has made certain Capital Contributions.
(b) The amount of money and the fair market value (as of the date of contribution) of any
property (other than money) contributed to the Company by a Member in respect of the issuance of a
Membership Interest to such Member shall constitute a Capital Contribution. Any reference in
this Agreement to the Capital Contribution of a Member shall include a Capital Contribution of its
predecessors in interest.
4.02 Loans. If the Company does not have sufficient cash to pay its obligations, any Member that may agree
to do so may, upon Special Approval, advance all or part of the needed funds for such obligation to
or on behalf of the Company. An advance described in this Section 4.02 constitutes a loan from the
Member to the Company, may bear interest at a rate comparable to the rate the Company could obtain
from third parties, and is not a Capital Contribution.
4.03 Return of Contributions. A Member is not entitled to the return of any part of its Capital Contributions or to be paid
interest in respect of its Capital Contributions. An unrepaid Capital Contribution is not a
liability of the Company or of any Member. No Member will be required to contribute or to lend any
cash or property to the Company to enable the Company to return any Members Capital Contributions.
ARTICLE 5
DISTRIBUTIONS
5.01 Distributions. Subject to Section 9.02, within 45 days following each Quarter other than any Quarter in which
the dissolution of the Company has commenced (the Distribution Date), the Company shall
distribute to the Members the Companys Available Cash on such Distribution Date.
ARTICLE 6
MANAGEMENT
6.01 Management.
(a) All management powers over the business and affairs of the Company shall be exclusively
vested in a Board of Directors (Board of Directors or Board) and, subject to the direction of
the Board of Directors, the Officers. The Officers and Directors shall each constitute a manager
of the Company within the meaning of the Delaware Act. Except as otherwise specifically provided
in this Agreement, no Member, by virtue of having the status of
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a Member, shall have or attempt to
exercise or assert any management power over the business and affairs of the Company or shall have
or attempt to exercise or assert actual or apparent authority to enter into contracts on behalf of,
or to otherwise bind, the Company. Except as otherwise specifically provided in this Agreement,
the authority and functions of the Board of Directors on the one hand and of the Officers on the
other shall be identical to the authority and functions of the board of directors and officers,
respectively, of a corporation organized under the Delaware General Corporation Law. Except as
otherwise specifically provided in this Agreement, the business and affairs of the Company shall be
managed under the direction of the Board of Directors, and the day-to-day activities of the Company
shall be conducted on the Companys behalf by the Officers, who shall be agents of the Company.
(b) In addition to the powers that now or hereafter can be granted to managers under the
Delaware Act and to all other powers granted under any other provision of this Agreement, except as
otherwise provided in this Agreement, the Board of Directors and the Officers shall have full power
and authority to do all things as are not restricted by this Agreement, the DCP GP Agreement, the
Delaware Act or applicable Law, on such terms as they may deem necessary or appropriate to conduct,
or cause to be conducted, the business and affairs of the Company.
(c) Notwithstanding anything herein to the contrary, without obtaining Extraordinary Approval,
the Company shall not, and shall not take any action to cause either
DCP GP or the MLP to, (i) make or consent to a general assignment for the benefit of its
respective creditors; (ii) file or consent to the filing of any bankruptcy, insolvency or
reorganization petition for relief under the United States Bankruptcy Code naming the Company, DCP
GP or the MLP, as applicable, or otherwise seek, with respect to the Company, DCP GP or the MLP,
relief from debts or protection from creditors generally; (iii) file or consent to the filing of a
petition or answer seeking for the Company, DCP GP or the MLP, as applicable, a liquidation,
dissolution, arrangement, or similar relief under any law; (iv) file an answer or other pleading
admitting or failing to contest the material allegations of a petition filed against the Company,
DCP GP or the MLP, as applicable, in a proceeding of the type described in any of clauses (i)
(iii) of this Section 6.01(c); (v) seek, consent to or acquiesce in the appointment of a receiver,
liquidator, conservator, assignee, trustee, sequestrator, custodian or any similar official for the
Company, DCP GP or the MLP, as applicable, or for all or any substantial portion of either entitys
properties; (vi) sell all or substantially all of the assets of the Company, DCP GP or the MLP;
(vii) dissolve or liquidate, except in the case of DCP GP, in accordance with Article XII of the
DCP GP Agreement; (viii) merge or consolidate; (ix) amend the MLP Partnership Agreement; or (x)
make a material change in the amount of the quarterly distributions made on the MLP Interests or
the payment of any material extraordinary distribution on the MLP Interests.
(d) Notwithstanding anything herein to the contrary, DEFS, as the sole Member of the Company,
shall have exclusive authority over the business and affairs of the Company that do not relate to
management and control of the MLP. The type of matter referred to in the prior sentence where
DEFS, as the sole Member of the Company, shall have exclusive authority shall include, but not be
limited to, (i) the amount and timing of distributions paid by the Company or DCP GP, (ii) the
issuance or repurchase of any equity interests in the Company or DCP GP, (iii) the prosecution,
settlement or management of any claim made directly against
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the Company or DCP GP, (iv) whether to
sell, convey, transfer or pledge any asset of the Company or DCP GP, (v) whether to amend, modify
or waive any rights relating to the assets of the Company or DCP GP (including the decision to
amend or forego distributions in respect of the Incentive Distribution Rights), and (vi) whether to
enter into any agreement to incur an obligation of the Company or DCP GP other than an agreement
entered into for and on behalf of the MLP for which the Company or DCP GP are liable exclusively by
virtue of DCP GPs capacity as general partner of the MLP or of any of its affiliates. Further,
DEFS, as the sole Member of the Company, shall have exclusive authority to cause the Company to
exercise the rights of the Company and those of DCP GP, as general partner of the MLP (or those
exercisable after DCP GP ceases to be the general partner of the MLP), pursuant to the following
provisions of the MLP Partnership Agreement:
(i) Section 2.4 (Purpose and Business), with respect to decisions to propose or approve the
conduct by the MLP of any business;
(ii) Sections 4.6(a) and (b) (Transfer of the General Partners General Partner Interest)
and Section 4.7 (Transfer of Incentive Distribution Rights), solely with respect to the decision
by DCP GP to transfer its general partner interest in the MLP or its Incentive Distribution Rights;
(iii) Section 5.2(b) (Contributions by the General Partner and its Affiliates), solely with
respect to the decision to make additional Capital Contributions to the MLP;
(iv) Section 5.8 (Limited Preemptive Right);
(v) Section 5.11 (Issuance of Class B Units in Connection with Reset of Incentive
Distribution Rights), with respect to any decision by the Company or DCP GP thereunder as a holder
of Incentive Distribution Rights or Class B Units;
(vi) Section 7.5(d) (relating to the right of DCP GP and its Affiliates to purchase Units or
other Partnership Securities and exercise rights related thereto) and Section 7.11 (Purchase and
Sale of Partnership Securities), solely with respect to decisions by the Company or DCP GP to
purchase or otherwise acquire and sell Partnership Securities for their own account;
(vii) Section 7.6(a) (Loans from the General Partner; Loans or Contributions from the
Partnership or Group Members), solely with respect to the decision by the Company or DCP GP to
lend funds to a Group Member, subject to the provisions of Section 7.9 of the MLP Partnership
Agreement;
(viii) Section 7.7 (Indemnification), solely with respect to any decision by the Company or
DCP GP to exercise their respective rights as Indemnitees;
(ix) Section 7.12 (Registration Rights of the General Partner and its Affiliates), solely
with respect to any decision to exercise registration rights and to take actions in connection
therewith;
7
(x) Section 11.1 (Withdrawal of the General Partner), solely with respect to the decision by
DCP GP to withdraw as general partner of the MLP and to giving notices required thereunder;
(xi) Section 11.3(a) and (b) (Interest of Departing General Partner and Successor General
Partner); and
(xii) Section 15.1 (Right to Acquire Limited Partner Interests).
(e) Without the approval of the Conflicts Committee of the Board of Directors of the Company,
the Company shall not take any action that would result in either the Company or DCP GP engaging in
any business or activity or incurring any debts or liabilities except in connection with or
incidental to (i) its performance as general partner of DCP GP or (ii) the acquiring, owning or
disposing of debt or equity securities of DCP GP.
6.02 Board of Directors.
(a) Generally. The Board of Directors shall initially consist of five natural persons and, in
the discretion of DEFS, may be increased to consist of up to 10 natural persons. The members of
the Board of Directors shall be appointed by DEFS, provided that (i) at least one member of the
Board of Directors at the time of the closing of the initial public offering of common units
representing limited partner interest of the MLP (the IPO) shall be a natural person who meets
the independence, qualification and experience requirements of the New York Stock Exchange, the
independence, qualification and experience requirements of Section 10A(m)(3) of the Securities
Exchange Act of 1934 (or any successor Law), the rules and regulations of the SEC and other
applicable Law (an Independent Director), (ii) at least two members of the Board of Directors
shall be natural persons who are Independent Directors at all times from and after the 90th day
following the effective date of the registration statement related to the IPO and (iii) at least
three members of the Board of Directors shall be natural persons who are Independent Directors at
all times from and after the first anniversary of the effective date of the registration statement
relating to the IPO; provided, however, that if at any time the Board of Directors does not include
the requisite number of Independent Directors as specified above, the Board of Directors shall
still have all powers and authority granted to it hereunder, but DEFS shall endeavor to appoint one
or more additional Independent Directors as necessary to come into compliance with this Section
6.02(a).
(b) Term; Resignation; Vacancies; Removal. Each Director, other than any Independent
Director, shall hold office until December 31 of the year in which such Director is appointed,
provided however, that in the event a Director, other than an Independent Director, is appointed
during the month of December in any particular year, such Director shall hold office until December
31 of the year following the year in which such Director is appointed. Each Independent Director
shall hold office until his successor is appointed and qualified or until his earlier resignation
or removal. Any Director may resign at any time upon written notice to the Board, the Chairman of
the Board, to the Chief Executive Officer or to any other Officer. Such resignation shall take
effect at the time specified therein, and unless otherwise specified therein no acceptance of such
resignation shall be necessary to make it effective. Vacancies and newly created directorships
resulting from any increase in the authorized number of Directors or from
8
any other cause shall be filled by DEFS. Any Director may be removed, with or without cause, by DEFS at any time, and the
vacancy in the Board caused by any such removal shall be filled by DEFS in accordance with the
provisions of the DEFS LLC Agreement.
(c) Voting; Quorum. Unless otherwise required by the Delaware Act, other Law or the
provisions hereof,
(i) each member of the Board of Directors shall have one vote;
(ii) except for matters requiring Special Approval, the presence at a meeting of a majority of
the members of the Board of Directors shall constitute a quorum at any such meeting for the
transaction of business; and
(iii) except for matters requiring Special Approval, the act of a majority of the members of
the Board of Directors present at a meeting duly called in accordance with Section 6.02(d) at which
a quorum is present shall be deemed to constitute the act of the Board of Directors.
(d) Meetings. Regular meetings of the Board of Directors shall be held at such times and
places as shall be designated from time to time by resolution of the Board of Directors. Special
meetings of the Board of Directors or meetings of any committee thereof may be called by written
request authorized by any member of the Board of Directors or a committee thereof on at least 48
hours prior written notice to the other members of such Board or committee. Any such notice, or
waiver thereof, need not state the purpose of such meeting, except as may otherwise be required by
law. Attendance of a Director at a meeting (including pursuant to the last sentence of this
Section 6.02(d)) shall constitute a waiver of notice of such meeting, except where such Director
attends the meeting for the express purpose of objecting to the transaction of any business on the
ground that the meeting is not lawfully called or convened. Any action required or permitted to be
taken at a meeting of the Board of Directors or any committee thereof may be taken without a
meeting, without prior notice and without a vote if a consent or consents in writing, setting forth
the action so taken, are signed by at least as many members of the Board of Directors or committee
thereof as would have been required to take such action at a meeting of the Board of Directors or
such committee. Members of the Board of Directors or any committee thereof may participate in and
hold a meeting by means of conference telephone, video conference or similar communications
equipment by means of which all Persons participating in the meeting can hear each other, and
participation in such meetings shall constitute presence in person at the meeting.
(e) Committees.
(i) Subject to compliance with this Article 6, committees of the Board of Directors shall have
and may exercise such of the powers and authority of the Board of Directors with respect to the
management of the business and affairs of the Company as may be provided in a resolution of the
Board of Directors. Any committee designated pursuant to this Section 6.02(e) shall choose its own
chairman, shall keep regular minutes of its proceedings and report the same to the Board of
Directors when requested, and, subject to Section 6.02(d), shall fix its own rules or procedures
and shall meet at such times and at such place or places as may be
9
provided by such rules or by
resolution of such committee or resolution of the Board of Directors. At every meeting of any such
committee, the presence of a majority of all the members thereof shall constitute a quorum and the
affirmative vote of a majority of the members present shall be necessary for the adoption by it of
any resolution (except for obtaining Special Approval at meetings of the Conflicts Committee, which
requires the affirmative vote of a majority of the members of such committee). The Board of
Directors may designate one or more Directors as alternate members of any committee who may replace
any absent or disqualified member at any meeting of such committee; provided, however, that any
such designated alternate of the Audit Committee or the Conflicts Committee must meet the standards
for an Independent Director. In the absence or disqualification of a member of a committee, the
member or members present at any meeting and not disqualified from voting, whether or not
constituting a quorum, may unanimously appoint another member of the Board of Directors to act at
the meeting in the place of the absent or disqualified member; provided, however, that any such
replacement member of the Audit Committee or the Conflicts Committee must meet the standards for an
Independent Director.
(ii) In addition to any other committees established by the Board of Directors pursuant to
Section 6.02(e)(i), the Board of Directors shall maintain a Conflicts Committee, which shall be composed of at least one Independent Director. The Conflicts
Committee shall be responsible for (A) approving or disapproving, as the case may be, any matters
regarding the business and affairs of the Company, DCP GP or the MLP considered by, or submitted
to, such Conflicts Committee at the request of the Board of Directors pursuant to the terms of the
DCP GP Agreement or the MLP Partnership Agreement, (B) approving any material amendments to the
Omnibus Agreement, (C) approving or disapproving, as the case may be, the entering into of any
material transaction with a Member or any Affiliate of a Member, other than transactions in the
ordinary course of business to the extent that the Board of Directors requests the Conflicts
Committee to make such determination, (D) amending (1) Section 2.07, (2) the definitions of
Independent Director in Section 6.02(a) or (3) this Section 6.02(e)(ii), and (E)
performing such other functions as the Board may assign from time to time or as may be specified in
a written charter of the Conflicts Committee. In acting or otherwise voting on the matters
referred to in this Section 6.02(e)(ii), to the fullest extent permitted by law, including Section
18-1101(c) of the Delaware Act and Section 17-1101(c) of the Delaware Revised Uniform Limited
Partnership Act, as amended from time to time, the Directors constituting the Conflicts Committee
shall consider only the interest of the MLP, including its respective creditors.
(iii) In addition to any other committees established by the Board of Directors pursuant to
Section 6.02(e)(i), the Board of Directors shall maintain an Audit Committee, which shall be
composed of (A) at least one Independent Director at the time of the closing of the IPO, (B) at
least two Independent Directors at all times from and after the 90th day following the effective
date of the registration statement related to the IPO and (C) at least three Independent Directors
at all times from and after the first anniversary of the effective date of the registration
statement related to the IPO. The Audit Committee shall be responsible for (A) assisting the Board
in monitoring (1) the integrity of the MLPs financial statements, (2) the qualifications and
independence of the MLPs independent accountants, (3) the performance the internal audit function
and independent accountants of the Company, DCP GP and the MLP, and (4) the MLPs compliance with
legal and regulatory requirements and (B) preparing the report
10
required by the rules of the SEC to be included in the MLPs annual report on Form 10-K. The
Audit Committee shall perform such other functions as the Board may assign from time to time or as
may be specified in a written charter for the Audit Committee adopted by the Board.
(iv) In addition to any other committees established by the Board of Directors pursuant to
Section 6.02(e)(i), the Board of Directors shall maintain an Compensation Committee, which shall
be composed of at least one Independent Director. The Compensation Committee shall be responsible
for setting the compensation for officers of the Company as well as administering any incentive
plans adopted by the Company. The Compensation Committee shall perform such other functions as the
Board may assign from time to time or as may be specified in a written charter for the Compensation
Committee adopted by the Board.
6.03 Officers.
(a) Generally. The Board of Directors, as set forth below, shall appoint officers of the
Company (Officers), who shall (together with the Directors) constitute managers of the Company
for the purposes of the Delaware Act. Unless provided otherwise by resolution of the Board of
Directors, the Officers shall have the titles, power, authority and duties described below in this
Section 6.03.
(b) Titles and Number. The Company may appoint one or more officers including a Chairman of
the Board (unless the Board of Directors provides otherwise), a Chief Executive Officer, a
President, one or more Vice Presidents, a Secretary, the Chief Financial Officer, any Treasurer and
one or more Assistant Secretaries and Assistant Treasurers and a General Counsel. Any person may
hold more then one office.
(c) Appointment and Term of Office. The Officers shall be appointed by the Board of Directors
at such time and for such term as the Board of Directors shall determine. Any Officer may be
removed, with or without cause, only by the Board of Directors. Vacancies in any office may be
filled only by the Board of Directors.
(d) Chairman of the Board. The Chairman of the Board shall preside at all meetings of the
Board of Directors and of the unitholders of the MLP; and he shall have such other powers and
duties as from time to time may be assigned to him by the Board of Directors.
(e)
Chief Executive Officer. Subject to the limitations imposed by this Agreement, any
employment agreement, any employee plan or any determination of the Board of Directors, the Chief
Executive Officer, subject to the direction of the Board of Directors, shall be the chief executive
officer of the Company and shall be responsible for the management and direction of the day-to-day
business and affairs of the Company, its other Officers, employees and agents, shall supervise
generally the affairs of the Company and shall have full authority to execute all documents and
take all actions that the Company may legally take. In the absence of the Chairman of the Board,
the Chief Executive Officer shall preside at all meetings of the unitholders of the MLP and at all
meetings of the Board of Directors provided that he is a director of the Company. The Chief
Executive Officer shall exercise such other powers and perform such other duties as may be assigned
to him by this Agreement or the Board of
11
Directors, including any duties and powers provided for in any employment agreement approved
by the Board of Directors.
(f) President. Subject to the limitations imposed by this Agreement, any employment
agreement, any employee plan or any determination of the Board of Directors, the President, subject
to the direction of the Board of Directors, shall be the chief executive officer of the Company in
the absence of a Chief Executive Officer and shall be responsible for the management and direction
of the day-to-day business and affairs of the Company, its other Officers, employees and agents,
shall supervise generally the affairs of the Company and shall have full authority to execute all
documents and take all actions that the Company may legally take. In the absence of the Chairman
of the Board and Chief Executive Officer, the President shall preside at all meetings of the
unitholders of the MLP and at all meetings of the Board of Directors provided that he is a director
of the Company. The President shall exercise such other powers and perform such other duties as
may be assigned to him by this Agreement or the Board of Directors, including any duties and powers
provided for in any employment agreement approved by the Board of Directors.
(g) Vice Presidents. In the absence of a Chief Executive Officer and the President, each Vice
President appointed by the Board of Directors shall have all of the powers and duties conferred
upon the President, including the same power as the President to execute documents on behalf of the
Company. Each such Vice President shall perform such other duties and may exercise such other
powers as may from time to time be assigned to him by the Board of Directors or the President.
(h) Secretary and Assistant Secretaries. The Secretary shall record or cause to be recorded
in books provided for that purpose the minutes of the meetings or actions of the Board of
Directors, shall see that all notices are duly given in accordance with the provisions of this
Agreement and as required by law, shall be custodian of all records (other than financial), shall
see that the books, reports, statements, certificates and all other documents and records required
by law are properly kept and filed, and, in general, shall perform all duties incident to the
office of Secretary and such other duties as may, from time to time, be assigned to him by this
Agreement, the Board of Directors or the President. The Assistant Secretaries shall exercise the
powers of the Secretary during that Officers absence or inability or refusal to act.
(i) Chief Financial Officer. The Chief Financial Officer shall keep and maintain, or cause to
be kept and maintained, adequate and correct books and records of account of the Company and DCP
GP. He shall receive and deposit all moneys and other valuables belonging to the Company in the
name and to the credit of the Company and shall disburse the same and only in such manner as the
Board of Directors or the appropriate Officer of the Company may from time to time determine. He
shall receive and deposit all moneys and other valuables belonging to DCP GP in the name and to the
credit of DCP GP and shall disburse the same and only in such manner as the Board of Directors or
the Chief Executive Officer may require. He shall render to the Board of Directors and the Chief
Executive Officer, whenever any of them request it, an account of all his transactions as Chief
Financial Officer and of the financial condition of the Company, and shall perform such further
duties as the Board of Directors or the Chief Executive Officer may require. The Chief Financial
Officer shall have the same power as the Chief Executive Officer to execute documents on behalf of
the Company.
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(j) Treasurer and Assistant Treasurers. The Treasurer shall have such duties as may be
specified by the Chief Financial Officer in the performance of his duties. The Assistant
Treasurers shall exercise the power of the Treasurer during that Officers absence or inability or
refusal to act. Each of the Assistant Treasurers shall possess the same power as the Treasurer to
sign all certificates, contracts, obligations and other instruments of the Company. If no
Treasurer or Assistant Treasurer is appointed and serving or in the absence of the appointed
Treasurer and Assistant Treasurer, any Vice President, or such other Officer as the Board of
Directors shall select, shall have the powers and duties conferred upon the Treasurer.
(k) General Counsel. The General Counsel, subject to the discretion of the Board of
Directors, shall be responsible for the management and direction of the day-to-day legal affairs of
the Company. The General Counsel shall perform such other duties and may exercise such other
powers as may from time to time be assigned to him by the Board of Directors or the President.
(l) Powers of Attorney. The Company may grant powers of attorney or other authority as
appropriate to establish and evidence the authority of the Officers and other persons.
(m) Delegation of Authority. Unless otherwise provided by resolution of the Board of
Directors, no Officer shall have the power or authority to delegate to any person such Officers
rights and powers as an Officer to manage the business and affairs of the Company.
(n) Tenure. The Board of Directors shall appoint Officers of the Company to serve from the
date hereof until the death, resignation or removal by the Board of Directors with or without cause
of such Officer.
6.04 Duties of Officers and Directors. Except as otherwise specifically provided in this Agreement or in the MLP Partnership Agreement,
the duties and obligations owed to the Company and to the Board of Directors by the Officers of the
Company and by members of the Board of Directors of the Company shall be the same as the respective
duties and obligations owed to a corporation organized under the Delaware General Corporation Law
by its officers and directors, respectively.
6.05 Compensation. The members of the Board of Directors who are neither Officers nor employees of the Company
shall be entitled to compensation as directors and committee members as approved by the Board and
shall be reimbursed for out-of-pocket expenses incurred in connection with attending meetings of
the Board of Directors or committees thereof.
6.06 Indemnification.
(a) To the fullest extent permitted by Law but subject to the limitations expressly provided
in this Agreement, each Indemnitee shall be indemnified and held harmless by the Company from and
against any and all losses, claims, damages, liabilities, joint or several,
expenses (including reasonable legal fees and expenses), judgments, fines, penalties,
interest, settlements and other amounts arising from any and all claims, demands, actions, suits or
proceedings, whether civil, criminal, administrative or investigative, in which any such Indemnitee
may be involved, or is threatened to be involved, as a party or otherwise, by reason of such
persons status as an Indemnitee; provided, however that the Indemnitee shall not be
13
indemnified
and held harmless if there has been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that, in respect of the matter for which the Indemnitee is
seeking indemnification pursuant to this Section 6.06, the Indemnitee acted in bad faith or engaged
in fraud, willful misconduct, or in the case of a criminal matter, acted with knowledge that the
Indemnitees conduct was unlawful; provided, further, no indemnification pursuant to this Section
6.06 shall be available to the Members or their Affiliates (other than the MLP and any Group
Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement,
the Omnibus Agreement or the Contribution Agreement. The termination of any action, suit or
proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere, or its
equivalent, shall not create a presumption that the Indemnitee acted in a manner contrary to that
specified above. Any indemnification pursuant to this Section 6.06 shall be made only out of the
assets of the Company, it being agreed that the Members shall not be personally liable for such
indemnification and shall have no obligation to contribute or loan any monies or property to the
Company to enable it to effectuate such indemnification.
(b) To the fullest extent permitted by law, expenses (including reasonable legal fees and
expenses) incurred by an Indemnitee who is indemnified pursuant to Section 6.06(a) in defending any
claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Company
prior to the final disposition of such claim, demand, action, suit or proceeding upon receipt by
the Company of an undertaking by or on behalf of the Indemnitee to repay such amount if it shall be
determined that the Indemnitee is not entitled to be indemnified as authorized in this Section
6.06.
(c) The indemnification provided by this Section 6.06 shall be in addition to any other rights
to which an Indemnitee may be entitled under any agreement, as a matter of law or otherwise, both
as to actions in the Indemnitees capacity as an Indemnitee and as to actions in any other
capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall
inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.
(d) The Company may purchase and maintain insurance, on behalf of the members of the Board of
Directors, the Officers and such other persons as the Board of Directors shall determine, against
any liability that may be asserted against or expense that may be incurred by such person in
connection with the Companys activities, regardless of whether the Company would have the power to
indemnify such person against such liability under the provisions of this Agreement.
(e) For purposes of this Section 6.06, the Company shall be deemed to have requested an
Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by the
Indemnitee of such Indemnitees duties to the Company also imposes duties on, or otherwise involves
services by, the Indemnitee to the plan or participants or beneficiaries of the plan; excise taxes
assessed on an Indemnitee with respect to an employee benefit plan
pursuant to applicable law shall constitute fines within the meaning of Section 6.06(a); and
action taken or omitted by the Indemnitee with respect to an employee benefit plan in the
performance of such Indemnitees duties for a purpose reasonably believed by such Indemnitee to be
in the interest of the participants and beneficiaries of the plan shall be deemed to be for a
purpose which is in, or not opposed to, the best interests of the Company.
14
(f) An Indemnitee shall not be denied indemnification in whole or in part under this Section
6.06 because the Indemnitee had an interest in the transaction with respect to which the
indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.
(g) The provisions of this Section 6.06 are for the benefit of the Indemnitees, their heirs,
successors, assigns and administrators and shall not be deemed to create any rights for the benefit
of any other Persons.
(h) No amendment, modification or repeal of this Section 6.06 or any provision hereof shall in
any manner terminate, reduce or impair either the right of any past, present or future Indemnitee
to be indemnified by the Company or the obligation of the Company to indemnify any such Indemnitee
under and in accordance with the provisions of this Section 6.06 as in effect immediately prior to
such amendment, modification or repeal with respect to claims arising from or relating to matters
occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when
such claims may arise or be asserted, provided such Person became an Indemnitee hereunder prior to
such amendment, modification or repeal.
(i) THE PROVISIONS OF THE INDEMNIFICATION PROVIDED IN THIS SECTION 6.06 ARE INTENDED BY THE
PARTIES TO APPLY EVEN IF SUCH PROVISIONS HAVE THE EFFECT OF EXCULPATING THE INDEMNITEE FROM LEGAL
RESPONSIBILITY FOR THE CONSEQUENCES OF SUCH PERSONS NEGLIGENCE, FAULT OR OTHER CONDUCT.
6.07 Liability of Indemnitees.
(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall
be liable for monetary damages to the Company, the Members or any other Person for losses sustained
or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a
final and non-appealable judgment entered by a court of competent jurisdiction determining that, in
respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful
misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitees conduct
was criminal.
(b) Subject to its obligations and duties as set forth in this Article 6, the Board of
Directors and any committee thereof may exercise any of the powers granted to it by this Agreement
and perform any of the duties imposed upon it hereunder either directly or by or through the
Companys Officers or agents, and neither the Board of Directors nor any committee
thereof shall be responsible for any misconduct or negligence on the part of any such Officer
or agent appointed by the Board of Directors or any committee thereof in good faith.
(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary
duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner
and any other Indemnitee acting in connection with the Partnerships business or affairs shall not
be liable to the Partnership or to any Partner for any acts or omissions taken in good faith
reliance on the provisions of this Agreement.
15
(d) Any amendment, modification or repeal of this Section 6.07 or any provision hereof shall
be prospective only and shall not in any way affect the limitations on liability under this Section
6.07 as in effect immediately prior to such amendment, modification or repeal with respect to
claims arising from or relating to matters occurring, in whole or in part, prior to such amendment,
modification or repeal, regardless of when such claims may be asserted.
6.08 Outside Activities.
(a) Except as specifically restricted by the provisions of the DCP GP Agreement or the MLP
Partnership Agreement, each Indemnitee, other than officers or employees of the Company, shall have
the right to engage in businesses of every type and description and other activities for profit and
to engage in and possess an interest in other business ventures of any and every type or
description, whether in businesses engaged in or anticipated to be engaged in by the Company or its
Subsidiaries, independently or with others, including business interests and activities in direct
competition with the business and activities of the Company or its Subsidiaries, and none of the
same shall constitute a breach of this Agreement or any duty expressed or implied by Law to the
Company or its Subsidiaries or any Member. Neither the Company or its Subsidiaries, any Member nor
any other Person shall have any rights by virtue of this Agreement, the DCP GP Agreement or the MLP
Partnership Agreement or the partnership relationship established hereby or thereby in any business
ventures of any Indemnitee.
(b) Notwithstanding anything to the contrary in this Agreement, (i) the engaging in
competitive activities by any Indemnitees, other than officers or employees of the Company, in
accordance with the provisions of this Section 6.08 is hereby approved by the Company and all
Members, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation
of any type whatsoever of any Indemnitee, other than officers or employees of the Company, for such
Indemnitees to engage in such business interests and activities in preference to or to the
exclusion of the Company and (iii) the Indemnitees, other than Officers or employees of the
Company, shall have no obligation hereunder or as a result of any duty expressed or implied by Law
to present business opportunities to the Company, DCP GP or the MLP.
(c) Each Member and each of its Affiliates may acquire additional Membership Interests and,
except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all
rights relating to such Membership Interests.
6.09 Resolution of Conflicts of Interest; Standard of Conduct and Modification of Duties.
(a) Unless otherwise expressly provided in this Agreement, whenever a potential conflict of
interest exists or arises between the Members or any of their Affiliates (other than the MLP or any
Group Member), on the one hand, and the MLP or any Group Member, on the other hand, any resolution
or course of action by the Board of Directors in respect of such conflict of interest shall be
permitted and deemed approved by all Members, and shall not constitute a breach of this Agreement
or of any agreement contemplated herein or therein, or of
16
any duty stated or implied by law or
equity, if the resolution or course of action in respect of such conflict of interest is (i)
approved by Special Approval, (ii) approved by the vote of a majority of the Units excluding Units
owned by the Members and their Affiliates, (iii) on terms no less favorable to the MLP or Group
Member, as the case may be, than those generally being provided to or available from unrelated
third parties or (iv) fair and reasonable to the MLP or Group Member, as the case may be, taking
into account the totality of the relationships between the parties involved (including other
transactions that may be particularly favorable or advantageous to the MLP or Group Member, as the
case may be). The Board of Directors shall be authorized but not required in connection with its
resolution of such conflict of interest to seek Special Approval of such resolution, and the Board
of Directors may also adopt a resolution or course of action that has not received Special
Approval. If Special Approval is not sought and the Board of Directors determines that the
resolution or course of action taken with respect to a conflict of interest satisfies either of the
standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its
decision, the Board of Directors acted in good faith, and in any proceeding brought by any Member
or by or on behalf of such Member or the MLP or Group Member, as the case may be, challenging such
approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming
such presumption.
(b) Whenever the Company makes a determination or takes or declines to take any other action,
or any of its Affiliates causes it to do so, in its capacity as the general partner of the General
Partner of the MLP as opposed to in its individual capacity, whether under this Agreement, or any
other agreement contemplated hereby or otherwise, then unless another express standard is provided
for in this Agreement, the Company, or such Affiliates causing it to do so, shall make such
determination or take or decline to take such other action in good faith and shall not be subject
to any other or different standards imposed by this Agreement, any other agreement contemplated
hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a
determination or other action to be in good faith for purposes of any action taken or delivered
to be taken by the Company in its capacity as the general partner of the General Partner of the
MLP, the Person or Persons making such determination or taking or declining to take such other
action must believe that the determination or other action is in the best interests of the MLP.
(c) Whenever the Company makes a determination or takes or declines to take any other action,
or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its
capacity as a general partner of the General Partner of the MLP, whether under this Agreement or
any other agreement contemplated hereby or otherwise, then the Company, or such Affiliates causing
it to do so, are entitled to make such determination or to take or decline to take such other
action free of any fiduciary duty or obligation whatsoever to the MLP or any
partner thereof, and the Company, or such Affiliates causing it to do so, shall not be
required to act in good faith or pursuant to any other standard imposed by this Agreement, any
other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation.
By way of illustration and not of limitation, whenever the phrase, at the option of the Company,
or some variation of that phrase, is used in this Agreement, it indicates that the Company is
acting in its individual capacity. For the avoidance of doubt, whenever the Company votes or
transfers its MLP Interests, or refrains from voting or transferring its MLP Interests, it shall be
acting in its individual capacity.
17
(d) Notwithstanding anything to the contrary in this Agreement, the Company and its Affiliates
shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset
of the MLP or any Group Member or (ii) permit the MLP or any Group Member to use any facilities or
assets of the Company and its Affiliates, except as may be provided in contracts entered into from
time to time specifically dealing with such use. Any determination by the Company or any of its
Affiliates to enter into such contracts shall be at its option.
(e) Whenever a particular transaction, arrangement or resolution of a conflict of interest is
required under this Agreement to be fair and reasonable to any Person, the fair and reasonable
nature of such transaction, arrangement or resolution shall be considered in the context of all
similar or related transactions.
ARTICLE 7
TAX MATTERS
7.01 Tax Returns and Tax Characterization.
(a) The Board of Directors shall cause to be prepared and timely filed (on behalf of the
Company) all federal, state and local tax returns required to be filed by the Company, including
making all elections on such tax returns. The Company shall bear the costs of the preparation and
filing of its returns.
(b) The Company and the Member acknowledge that for federal income tax purposes, the Company
will be disregarded as an entity separate from the Member pursuant to Treasury Regulation
§301.7701-3 as long as all of the Membership Interests in the Company are owned by DEFS.
ARTICLE 8
BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS
8.01 Maintenance of Books.
(a) The Board of Directors shall keep or cause to be kept at the principal office of the
Company or at such other location approved by the Board of Directors complete and
accurate books and records of the Company, supporting documentation of the transactions with
respect to the conduct of the Companys business and minutes of the proceedings of the Board of
Directors and any other books and records that are required to be maintained by applicable Law.
(b) The books of account of the Company shall be maintained on the basis of a fiscal year that
is the calendar year and on an accrual basis in accordance with United States generally accepted
accounting principles, consistently applied.
8.02 Reports. The Board of Directors shall cause to be prepared and delivered to each Member such reports,
forecasts, studies, budgets and other information as the Members may reasonably request from time
to time.
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8.03 Bank Accounts. Funds of the Company shall be deposited in such banks or other depositories as shall be
designated from time to time by the Board of Directors. All withdrawals from any such depository
shall be made only as authorized by the Board of Directors and shall be made only by check, wire
transfer, debit memorandum or other written instruction.
ARTICLE 9
DISSOLUTION, WINDING-UP AND TERMINATION
9.01 Dissolution.
(a) Subject to compliance with Section 6.01(c), the Company shall dissolve and its affairs
shall be wound up on the first to occur of the following events (each a Dissolution Event):
(i) the unanimous consent of the Board of Directors;
(ii) the entry of a decree of judicial dissolution of the Company under Section 18-802 of the
Delaware Act; and
(iii) at any time there are no Members of the Company, unless the Company is continued in
accordance with the Delaware Act or this Agreement.
(b) No other event shall cause a dissolution of the Company.
(c) Upon the occurrence of any event that causes there to be no Members of the Company, to the
fullest extent permitted by law, the personal representative of the last remaining Member is hereby
authorized to, and shall, within 90 days after the occurrence of the event that terminated the
continued membership of such Member in the Company, agree in writing (i) to continue the Company
and (ii) to the admission of the personal representative or its nominee or designee, as the case
may be, as a substitute Member of the Company, effective as of
the occurrence of the event that terminated the continued membership of such Member in the
Company.
(d) Notwithstanding any other provision of this Agreement, the Bankruptcy of a Member shall
not cause such Member to cease to be a member of the Company, and, upon the occurrence of such an
event, the Company shall continue without dissolution.
9.02 Winding-Up and Termination.
(a) On the occurrence of a Dissolution Event, the Board of Directors shall select one or more
Persons to act as liquidator. The liquidator shall proceed diligently to wind up the affairs of
the Company and make final distributions as provided herein and in the Delaware Act. The costs of
winding up shall be borne as a Company expense. Until final distribution, the liquidator shall
continue to operate the Company properties with all of the power and authority of the Board of
Directors. The steps to be accomplished by the liquidator are as follows:
(i) as promptly as possible after dissolution and again after final winding up, the liquidator
shall cause a proper accounting to be made by a recognized firm of
19
certified public accountants of
the Companys assets, liabilities, and operations through the last calendar day of the month in
which the dissolution occurs or the final winding up is completed, as applicable;
(ii) the liquidator shall discharge from Company funds all of the debts, liabilities and
obligations of the Company or otherwise make adequate provision for payment and discharge thereof
(including the establishment of a cash escrow fund for contingent liabilities in such amount and
for such term as the liquidator may reasonably determine); and
(iii) all remaining assets of the Company shall be distributed to the Members as follows:
(A) the liquidator may sell any or all Company property, including to Members;
and
(B) Company property (including cash) shall be distributed to the Members.
(b) The distribution of cash or property to a Member in accordance with the provisions of this
Section 9.02 constitutes a complete return to the Member of its Capital Contributions and a
complete distribution to the Member of its share of all the Companys property and constitutes a
compromise to which all Members have consented within the meaning of Section 18-502(b) of the
Delaware Act. No Member shall be required to make any Capital Contribution to the Company to
enable the Company to make the distributions described in this Section 9.02.
(c) On completion of such final distribution, the liquidator shall file a certificate of
cancellation with the Secretary of State of the State of Delaware and take such other actions as
may be necessary to terminate the existence of the Company.
ARTICLE 10
MERGER, CONSOLIDATION OR CONVERSION
10.01 Authority. Subject to compliance with Section 6.01(c), the Company may merge or consolidate with one or
more corporations, limited liability companies, statutory trusts or associations, real estate
investment trusts, common law trusts or unincorporated businesses, including a partnership (whether
general or limited (including a limited liability partnership)) or convert into any such entity,
whether such entity is formed under the laws of the State of Delaware or any other state of the
United States of America, pursuant to a written agreement of merger or consolidation (Merger
Agreement) or a written plan of conversion (Plan of Conversion), as the case may be, in
accordance with this Article 10. The surviving entity to any such merger, consolidation or
conversion is referred to herein as the Surviving Business Entity.
10.02 Procedure for Merger, Consolidation or Conversion.
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(a) The merger, consolidation or conversion of the Company pursuant to this Article 10
requires the prior approval of a majority of the Board of Directors and compliance with Section
10.03.
(b) If the Board of Directors shall determine to consent to a merger or consolidation, the
Board of Directors shall approve the Merger Agreement, which shall set forth:
(i) the names and jurisdictions of formation or organization of each of the business entities
proposing to merge or consolidate;
(ii) the name and jurisdiction of formation or organization of the Surviving Business Entity
that is to survive the proposed merger or consolidation;
(iii) the terms and conditions of the proposed merger or consolidation;
(iv) the manner and basis of exchanging or converting the equity securities of each
constituent business entity for, or into, cash, property or interests, rights, securities or
obligations of the Surviving Business Entity; and (A) if any general or limited partner interests,
securities or rights of any constituent business entity are not to be exchanged or converted solely
for, or into, cash, property or general or limited partner interests, rights, securities or
obligations of the Surviving Business Entity, the cash, property or interests, rights, securities
or obligations of any general or limited partnership, corporation, trust, limited liability
company, unincorporated business or other entity (other than the Surviving Business Entity) which
the holders of such general or limited partner interests, securities or rights are to receive in
exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of
securities represented by certificates, upon the surrender of such certificates, which cash,
property or general or limited partner interests, rights, securities or obligations of the
Surviving Business Entity or any general or limited partnership, corporation, trust, limited
liability company, unincorporated business or other entity (other than the Surviving Business
Entity), or evidences thereof, are to be delivered;
(v) a statement of any changes in the constituent documents or the adoption of new constituent
documents (the articles or certificate of incorporation, articles of trust, declaration of trust,
certificate or agreement of limited partnership, operating agreement or other similar charter or
governing document) of the Surviving Business Entity to be effected by such merger or
consolidation;
(vi) the effective time of the merger, which may be the date of the filing of the certificate
of merger pursuant to Section 10.04 or a later date specified in or determinable in accordance with
the Merger Agreement (provided, that if the effective time of the merger is to be later than the
date of the filing of such certificate of merger, the effective time shall be fixed at a date or
time certain at or prior to the time of the filing of such certificate of merger and stated
therein); and
(vii) such other provisions with respect to the proposed merger or consolidation as are deemed
necessary or appropriate by the Board of Directors.
21
(c) If the Board of Directors shall determine to consent to the conversion, the Board of
Directors shall approve and adopt a Plan of Conversion containing such terms and conditions that
the Board of Directors determines to be necessary or appropriate.
10.03 Approval by Members of Merger or Consolidation.
(a) The Board of Directors, upon its approval of the Merger Agreement or Plan of Conversion,
as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as
applicable, be submitted to a vote of the Members, whether at a meeting or by written consent. A
copy or a summary of the Merger Agreement or the Plan of Conversion, as applicable, shall be
included in or enclosed with the notice of a special meeting or the written consent.
(b) The Merger Agreement or the Plan of Conversion, as applicable, shall be approved upon
receiving the affirmative vote or consent of the holders of a majority of the Members.
(c) After such approval by vote or consent of the Limited Partners, and at any time prior to
the filing of the certificate of merger, consolidation or conversion pursuant to Section 10.04, the
merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set
forth in the Merger Agreement or the Plan of Conversion, as the case may be.
10.04 Certificate of Merger, Consolidation or Conversion.
(a) Upon the required approval, if any, by the Board of Directors and the Members of a Merger
Agreement or a Plan of Conversion, as the case may be, a certificate of merger, consolidation or
conversion, as applicable, shall be executed and filed with the Secretary of State of the State of
Delaware in conformity with the requirements of the Delaware Act.
(b) At the effective time of the certificate of merger or consolidation:
(i) all of the rights, privileges and powers of each of the business entities that has merged
or consolidated, and all property, real, personal and mixed, and all debts due to any of those
business entities and all other things and causes of action belonging to each of those business
entities shall be vested in the Surviving Business Entity and after the merger or consolidation
shall be the property of the Surviving Business Entity to the extent they were property of each
constituent business entity;
(ii) the title to any real property vested by deed or otherwise in any of those constituent
business entities shall not revert and is not in any way impaired because of the merger or
consolidation;
(iii) all rights of creditors and all liens on or security interest in property of any of
those constituent business entities shall be preserved unimpaired; and
(iv) all debts, liabilities and duties of those constituent business entities shall attach to
the Surviving Business Entity, and may be enforced against it to the same extent as if the debts,
liabilities and duties had been incurred or contracted by it.
22
(c) At the effective time of the certificate of conversion:
(i) the Company shall continue to exist, without interruption, but in the organizational form
of the converted entity rather than in its prior organizational form;
(ii) all rights, title, and interests to all real estate and other property owned by the
Company shall continue to be owned by the converted entity in its new organizational form without
reversion or impairment, without further act or deed, and without any transfer or assignment having
occurred, but subject to any existing liens or other encumbrances thereon;
(iii) all liabilities and obligations of the Company shall continue to be liabilities and
obligations of the converted entity in its new organizational form without impairment or diminution
by reason of the conversion;
(iv) all rights of creditors or other parties with respect to or against the prior interest
holders or other owners of the Company in their capacities as such in existence as of the effective
time of the conversion will continue in existence as to those liabilities and obligations and may
be pursued by such creditors and obligees as if the conversion did not occur;
(v) a proceeding pending by or against the Company or by or against any of the Members in
their capacities as such may be continued by or against the converted entity in its new
organizational form and by or against the prior members without any need for substitution of
parties; and
(vi) the Company securities that are to be converted into partnership interests, shares,
evidences of ownership, or other securities in the converted entity as provided in the Plan of
Conversion or certificate of conversion shall be so converted, and the Members shall be entitled
only to the rights provided in the Plan of Conversion or certificate of conversion.
(d) A merger, consolidation or conversion effected pursuant to this Article 10 shall not (i)
be deemed to result in a transfer or assignment of assets or liabilities from one entity to another
having occurred or (ii) require the Company (if it is not the Surviving Business Entity) to wind up
its affairs, pay its liabilities or distribute its assets as required under Article 9 of this
Agreement or under the applicable provisions of the Delaware Act.
ARTICLE 11
GENERAL PROVISIONS
11.01 Notices. Except as expressly set forth to the contrary in this Agreement, all notices, requests or
consents provided for or permitted to be given under this Agreement must be in writing and must be
delivered to the recipient in person, by courier or mail or by facsimile or other electronic
transmission and a notice, request or consent given under this Agreement is effective on receipt by
the Person to receive it; provided, however, that a facsimile or other electronic transmission that
is transmitted after the normal business hours of the recipient shall be deemed effective on the
next Business Day. All notices, requests and consents to be sent to a Member must be sent to or
made at the addresses given for that Member as that Member may specify by notice to the other
Members. Any notice, request or consent to the Company must be
23
given to all of the Members.
Whenever any notice is required to be given by applicable Law, the Organizational Certificate or
this Agreement, a written waiver thereof, signed by the Person entitled to notice, whether before
or after the time stated therein, shall be deemed equivalent to the giving of such notice.
Whenever any notice is required to be given by Law, the Organizational Certificate or this
Agreement, a written waiver thereof, signed by the Person entitled to notice, whether before or
after the time stated therein, shall be deemed equivalent to the giving of such notice.
11.02 Entire Agreement; Supersedure. This Agreement constitutes the entire agreement of the Members and
their respective Affiliates relating to the subject matter hereof and supersedes all prior
contracts or agreements with respect to such subject matter, whether oral or written.
11.03 Effect of Waiver or Consent. Except as provided in this Agreement, a waiver or consent, express or
implied, to or of any breach or default by any Person in the performance by that Person of its
obligations with respect to the Company is not a consent or waiver to or of any other breach or
default in the performance by that Person of the same or any other obligations of that Person with
respect to the Company. Except as provided in this Agreement, failure on the part of a Person to
complain of any act of any Person or to declare any Person in default with respect to the Company,
irrespective of how long that failure continues, does not constitute a waiver by that Person of its
rights with respect to that default until the applicable statute-of-limitations period has run.
11.04 Amendment or Restatement. This Agreement may be amended or restated only by a written instrument
executed by all Members; provided, however, that notwithstanding anything to the contrary contained
in this Agreement, each Member agrees that the Board of Directors, without the approval of any
Member, may amend any provision of the Organizational Certificate and this Agreement, and may
authorize any Officer to execute, swear to, acknowledge, deliver, file and record any such
amendment and whatever documents may be required in connection therewith, to reflect any change
that does not require consent or approval (or for which such consent or approval has been obtained)
under this Agreement or does not materially adversely affect the rights of the Members.
11.05 Binding Effect. This Agreement is binding on and shall inure to the benefit of the Members and
their respective heirs, legal representatives, successors and assigns.
11.06 Governing Law; Severability. THIS AGREEMENT IS GOVERNED BY AND SHALL BE CONSTRUED IN ACCORDANCE WITH THE LAW OF THE STATE OF
DELAWARE, EXCLUDING ANY CONFLICT-OF-LAWS RULE OR PRINCIPLE THAT MIGHT REFER THE GOVERNANCE OR THE
CONSTRUCTION OF THIS AGREEMENT TO THE LAW OF ANOTHER JURISDICTION. In the event of a direct
conflict between the provisions of this Agreement and (a) any provision of the Organizational
Certificate, or (b) any mandatory, non-waivable provision of the Delaware Act, such provision of
the Organizational Certificate or the Delaware Act shall control. If any provision of the Delaware
Act provides that it may be varied or superseded in the limited liability company agreement (or
otherwise by agreement of the members or managers of a limited liability company), such provision
shall be deemed superseded and waived in its entirety if this Agreement contains a provision
addressing
24
the same issue or subject matter. If any provision of this Agreement or the application
thereof to any Person or circumstance is held invalid or unenforceable to any extent, (a) the
remainder of this Agreement and the application of that provision to other Persons or circumstances
is not affected thereby and that provision shall be enforced to the greatest extent permitted by
Law, and (b) the Members or Directors (as the case may be) shall negotiate in good faith to replace
that provision with a new provision that is valid and enforceable and that puts the Members in
substantially the same economic, business and legal position as they would have been in if the
original provision had been valid and enforceable.
11.07 Further Assurances. In connection with this Agreement and the transactions contemplated hereby,
each Member shall execute and deliver any additional documents and instruments and perform any
additional acts that may be necessary or appropriate to effectuate and perform the provisions of
this Agreement and those transactions.
11.08 Offset. Whenever the Company is to pay any sum to any Member, any amounts that a Member owes the
Company may be deducted from that sum before payment.
11.09 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as
if all signing parties had signed the same document. All counterparts shall be construed together
and constitute the same instrument.
25
IN WITNESS WHEREOF, DEFS has executed this Agreement as the sole member as of the date first
set forth above.
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MEMBER:
DUKE ENERGY FIELD SERVICES, LLC
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By: |
/s/ Brent L. Backes
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Name: |
Brent L. Backes |
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Title: |
Vice President, General Counsel and
Secretary |
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Signature
Page Amended and Restated Limited Liability Agreement
of DCP Midstream GP, LLC
Attachment I
Defined Terms
Affiliate with respect to any Person, each Person Controlling, Controlled by or under
common Control with such first Person; provided that, for the evidence of doubt, the term
Affiliate, includes any Person that, directly or indirectly, is the beneficial owner of at least
25% of the equity interest in DEFS or has the right to appoint at least 25% of the members of the
board of directors of DEFS.
Agreement this Amended and Restated Limited Liability Company Agreement of DCP Midstream
GP, LLC, as the same may be amended, modified, supplemented or restated from time to time.
Audit Committee Section 6.02(e)(iii).
Available Cash as of any Distribution Date, (a) all cash and cash equivalents of the
Company on hand on such date, less (b) the amount of any cash reserves determined to be appropriate
by the Board of Directors.
Bankruptcy or Bankrupt with respect to any Person, that (a) such Person (i) makes an
assignment for the benefit of creditors; (ii) files a voluntary petition in bankruptcy; (iii) is
insolvent, or has entered against such Person an order for relief in any bankruptcy or insolvency
proceeding; (iv) files a petition or answer seeking for such Person any reorganization,
arrangement, composition, readjustment, liquidation, dissolution or similar relief under any Law;
(v) files an answer or other pleading admitting or failing to contest the material allegations of a
petition filed against such Person in a proceeding of the type described in subclauses (i) through
(iv) of this clause (a); or (vi) seeks, consents to or acquiesces in the appointment of a trustee,
receiver or liquidator of such Person or of all or any substantial part of such Persons
properties; or (b) 120 Days have passed after the commencement of any proceeding seeking
reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief
under any Law, if the proceeding has not been dismissed, or 90 Days have passed after the
appointment without such Persons consent or acquiescence of a trustee, receiver or liquidator of
such Person or of all or any substantial part of such Persons properties, if the appointment is
not vacated or stayed, or 90 Days have passed after the date of expiration of any such stay, if the
appointment has not been vacated.
Board of Directors or Board Section 6.01.
Business Day any Day other than a Saturday, a Sunday or a Day on which national banking
associations in the State of Texas are authorized or required by Law to close.
Capital Contribution Section 4.01(b).
Class B Units has the meaning ascribed to such term in the MLP Partnership Agreement.
A-1
Commitment means (a) options, warrants, convertible securities, exchangeable securities,
subscription rights, conversion rights, exchange rights, or other contracts, agreements or
commitments that could require a Person to issue any of its Equity Interests or to sell any Equity
Interests it owns in another Person; (b) any other securities convertible into, exchangeable or
exercisable for, or representing the right to subscribe for any Equity Interest of a Person or
owned by a Person; (c) statutory or contractual pre-emptive rights or pre-emptive rights granted
under a Persons organizational or constitutive documents; and (d) stock appreciation rights,
phantom stock, profit participation, or other similar rights with respect to a Person.
Company initial paragraph of this Agreement.
Compensation Committee Section 6.02(e)(iv)
Conflicts Committee Section 6.02(e)(ii).
Contribution Agreement has the meaning ascribed to such term in the MLP Partnership Agreement.
Control shall mean the possession, directly or indirectly, of the power and authority to
direct or cause the direction of the management and policies of a Person, whether through ownership
or control of Voting Stock, by contract or otherwise.
Day a calendar Day; provided, however, that, if any period of Days referred to in this
Agreement shall end on a Day that is not a Business Day, then the expiration of such period shall
be automatically extended until the end of the first succeeding Business Day.
DCP GP DCP Midstream GP, LP, as the general partner of the MLP.
DCP GP Agreement the First Amended and Restated Agreement of Limited Partnership of DCP
Midstream GP, LP, dated effective as of December 7, 2005, as amended, supplemented, amended and
restated, or otherwise modified from time to time.
DEFS initial paragraph of this Agreement.
DEFS LLC Agreement means the Second Amended and Restated Limited Liability Company
Agreement of DEFS.
Delaware Act the Delaware Limited Liability Company Act and any successor statute, as
amended from time to time.
Delaware General Corporation Law Title 8 of the Delaware Code, as amended from time to
time.
Director each member of the Board of Directors elected as provided in Section 6.02.
Dissolution Event Section 9.01(a).
A-2
Distribution Date Section 5.01.
Effective Date initial paragraph of this Agreement.
Equity Interest (a) with respect to a corporation, any and all shares of capital stock and
any Commitments with respect thereto, (b) with respect to a partnership, limited liability company,
trust or similar Person, any and all units, interests or other partnership, limited liability
company, trust or similar interests, and any Commitments with respect thereto, and (c) any other
direct or indirect equity ownership or participation in a Person (including any incentive
distribution rights).
Existing Agreement Recitals.
Extraordinary Approval written approval of DEFS.
Group Member means any of the MLP and its Subsidiaries.
Incentive Distribution Rights has the meaning ascribed thereto in the MLP Partnership
Agreement.
Indemnitee each of (a) the Company and any Person who is or was an Affiliate of the
Company, (b) any Person who is or was a member, director, officer, fiduciary or trustee of the
Company, (c) any Person who is or was an officer, member, partner, director, employee, agent or
trustee of the General Partner or any Affiliate of the General Partner, or any Affiliate of any
such Person, and (d) any Person who is or was serving at the request of the General Partner or any
such Affiliate as a director, officer, employee, member, partner, agent, fiduciary or trustee of
another Person; provided, that a Person shall not be an Indemnitee by reason of providing, on a
fee-for-services basis, trustee, fiduciary or custodial services and (e) any Person the Company
designates as an Indemnitee for purposes of this Agreement.
Independent Director Section 6.02(a).
Law any applicable constitutional provision, statute, act, code, law, regulation, rule,
ordinance, order, decree, ruling, proclamation, resolution, judgment, decision, declaration or
interpretative or advisory opinion or letter of a governmental authority.
Liability any liability or obligation, whether known or unknown, asserted or unasserted,
absolute or contingent, matured or unmatured, conditional or unconditional, latent or patent,
accrued or unaccrued, liquidated or unliquidated, or due or to become due.
Member any Person executing this Agreement as of the date of this Agreement as a member or
hereafter admitted to the Company as a member as provided in this Agreement, but such term does not
include any Person who has ceased to be a member in the Company.
Membership Interest with respect to any Member, (a) that Members status as a Member; (b)
that Members share of the income, gain, loss, deduction and credits of, and the right to receive
distributions from, the Company; (c) all other rights, benefits and privileges enjoyed by that
Member (under the Delaware Act, this Agreement or otherwise) in its capacity as
A-3
a Member; and (d) all obligations, duties and liabilities imposed on that Member (under the
Delaware Act, this Agreement or otherwise) in its capacity as a Member, including any obligations
to make Capital Contributions.
Merger Agreement Section 10.01.
MLP DCP Midstream Partners, LP, a Delaware limited partnership.
MLP Interests the limited partner interests of the MLP, regardless of class or category of
limited partner interests.
MLP Partnership Agreement means the Amended and Restated Agreement of Limited Partnership
of the MLP, dated as of December 7, 2005, as amended or restated from time to time.
National Securities Exchange has the meaning ascribed to such term in the MLP Partnership
Agreement.
Officers any person elected as an officer of the Company as provided in Section 6.03(a),
but such term does not include any person who has ceased to be an officer of the Company.
Omnibus Agreement Omnibus Agreement, dated December 7, 2005, among the Company, DCP GP and
DEFS, as amended or restated from time to time.
Organizational Certificate Section 2.01.
Partnership Securities has the meaning ascribed to such term in the MLP Partnership Agreement.
Person a natural person, partnership (whether general or limited), limited liability
company, governmental entity, trust, estate, association, corporation, venture, custodian, nominee
or any other individual or entity in its own or any representative capacity.
Plan of Conversion Section 10.01.
Quarter unless the context requires otherwise, a calendar quarter.
SEC the United States Securities and Exchange Commission.
Special Approval approval by a majority of the members of the Conflicts Committee.
Subsidiary with respect to any relevant Person, (a) a corporation of which more than 50% of
the Voting Stock is owned, directly or indirectly, at the date of determination, by such relevant
Person, by one or more Subsidiaries of such relevant Person or a combination thereof, (b) a
partnership (whether general or limited) in which such relevant Person, one or more Subsidiaries of
such relevant Person or a combination thereof is, at the date of
A-4
determination, a general or limited partner of such partnership, but only if more than 50% of
the partnership interests of such partnership (considering all of the partnership interests of the
partnership as a single class) is owned, directly or indirectly, at the date of determination, by
such relevant Person, by one or more Subsidiaries of such relevant Person, or a combination
thereof, or (c) any other Person (other than a corporation or a partnership) in which such relevant
Person, one or more Subsidiaries of such relevant Person, or a combination thereof, directly or
indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii)
the power to elect or direct the election of a majority of the directors or other governing body of
such other Person.
Surviving Business Entity Section 10.01.
Underwriting Agreement has the meaning ascribed to such term in the MLP Partnership
Agreement.
Units has the meaning ascribed to such term in the MLP Partnership Agreement.
Voting Stock with respect to any Person, Equity Interests in such Person, the holders of
which are ordinarily, in the absence of contingencies, entitled to vote for the election of, or
otherwise appoint, directors (or Persons with management authority performing similar functions) of
such Person.
Withdraw, Withdrawing and Withdrawal the withdrawal, resignation or retirement of a Member
from the Company as a Member.
A-5
exv10w16
Exhibit 10.16
CONTRIBUTION AGREEMENT
among
DCP LP Holdings, LLC,
DCP Midstream GP, LP,
DCP Midstream, LLC
and
DCP Midstream Partners, LP
February 24, 2009
Table of Contents
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ARTICLE I CERTAIN DEFINITIONS |
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1.1 Certain Defined Terms |
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1.2 Other Definitional Provisions |
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1.3 Headings |
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1.4 Other Terms |
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13 |
|
|
|
|
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ARTICLE II CONTRIBUTION OF THE SUBJECT INTERESTS, ISSUANCE OF THE UNITS AND CONSIDERATION |
|
|
13 |
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2.1 The Transaction |
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13 |
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2.2 Consideration |
|
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13 |
|
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ARTICLE III ADJUSTMENTS AND SETTLEMENT |
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13 |
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3.1 Adjustments |
|
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13 |
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3.2 Preliminary Settlement Statement |
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14 |
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3.3 Final Settlement Statement |
|
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14 |
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3.4 Dispute Procedures |
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14 |
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3.5 Payments |
|
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14 |
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3.6 Access to Records |
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14 |
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ARTICLE IV REPRESENTATIONS AND WARRANTIES OF HOLDINGS |
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15 |
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4.1 Organization, Good Standing, and Authority |
|
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15 |
|
4.2 Enforceability |
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15 |
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4.3 No Conflicts |
|
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15 |
|
4.4 Consents, Approvals, Authorizations and Governmental Regulations |
|
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16 |
|
4.5 Taxes |
|
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16 |
|
4.6 Litigation; Compliance with Laws |
|
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17 |
|
4.7 Contracts |
|
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18 |
|
4.8 Title to Assets; Intellectual Property |
|
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19 |
|
4.9 Preferential Rights to Purchase |
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19 |
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4.10 Brokers or Finders Fees |
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19 |
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4.11 Compliance with Property Instruments |
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19 |
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4.12 Environmental Matters |
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19 |
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4.13 Employee Matters |
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20 |
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4.14 Benefit Plan Liabilities |
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20 |
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4.15 No Foreign Person |
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20 |
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4.16 Capitalization of the Subject Interests |
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20 |
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4.17 Subsidiaries and Other Equity Interests |
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21 |
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4.18 Bank Accounts |
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21 |
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4.19 [Reserved] |
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21 |
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4.20 Investment Intent |
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21 |
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4.21 Financial Statements; Internal Controls; Undisclosed Liabilities |
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21 |
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4.22 No Other Representations or Warranties; Schedules |
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21 |
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ARTICLE V REPRESENTATIONS AND WARRANTIES OF MLP |
|
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22 |
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5.1 Organization, Good Standing, and Authorization |
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22 |
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5.2 Enforceability |
|
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22 |
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i
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5.3 No Conflicts |
|
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22 |
|
5.4 Consents, Approvals, Authorizations and Governmental Regulations |
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22 |
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5.5 Litigation |
|
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23 |
|
5.6 Independent Investigation |
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23 |
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5.7 Brokers or Finders Fees |
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24 |
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5.8 Investment Intent |
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24 |
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5.9 Available Funds |
|
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24 |
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ARTICLE VI COVENANTS AND ACCESS |
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24 |
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6.1 Conduct of Business |
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24 |
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6.2 Casualty Loss |
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26 |
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6.3 Access, Information and Access Indemnity |
|
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27 |
|
6.4 Regulatory Filings; Hart-Scott-Rodino Filing |
|
|
27 |
|
6.5 Limitation on Casualty Losses and Other Matters |
|
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28 |
|
6.6 Supplements to Exhibits and Schedules |
|
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28 |
|
6.7 Preservation of Records |
|
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29 |
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6.8 [Reserved] |
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29 |
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6.9 Capital Projects |
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29 |
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6.10 [Reserved] |
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30 |
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6.11 Tax Covenants; Preparation of Tax Returns |
|
|
30 |
|
6.12 Financial Statements and Financial Records |
|
|
30 |
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|
|
|
|
|
ARTICLE VII CONDITIONS TO CLOSING |
|
|
30 |
|
|
7.1 HOLDINGS/GPs Conditions |
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30 |
|
7.2 MLPs Conditions |
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31 |
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ARTICLE VIII CLOSING |
|
|
31 |
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8.1 Time and Place of Closing |
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31 |
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8.2 Deliveries at Closing |
|
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32 |
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ARTICLE IX TERMINATION |
|
|
32 |
|
|
9.1 Termination |
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32 |
|
9.2 Effect of Termination Prior to Closing |
|
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33 |
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|
ARTICLE X INDEMNIFICATION |
|
|
33 |
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|
10.1 Indemnification by MLP |
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33 |
|
10.2 Indemnification by HOLDINGS |
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33 |
|
10.3 Deductibles, Caps, Survival and Certain Limitations |
|
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34 |
|
10.4 Notice of Asserted Liability; Opportunity to Defend |
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35 |
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10.5 Materiality Conditions |
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37 |
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10.6 Exclusive Remedy |
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37 |
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10.7 Negligence and Strict Liability Waiver |
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38 |
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10.8 Limitation on Damages |
|
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38 |
|
10.9 Bold and/or Capitalized Letters |
|
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38 |
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ARTICLE XI MISCELLANEOUS PROVISIONS |
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38 |
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11.1 Expenses |
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38 |
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11.2 Further Assurances |
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38 |
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11.3 Transfer Taxes |
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39 |
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11.4 Assignment |
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39 |
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ii
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11.5 Entire Agreement, No Amendment of Prior Transaction Agreement, Amendments and Waiver |
|
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39 |
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11.6 Severability |
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39 |
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11.7 Counterparts |
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39 |
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11.8 Governing Law, Dispute Resolution and Arbitration |
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39 |
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11.9 Notices and Addresses |
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42 |
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11.10 Press Releases |
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43 |
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11.11 Offset |
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43 |
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11.12 No Partnership; Third Party Beneficiaries |
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43 |
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11.13 Negotiated Transaction |
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43 |
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Schedules
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|
|
1.1(a) |
|
Excluded Assets |
1.1(b) |
|
Excluded Contracts Including Swaps |
1.1(c) |
|
HOLDINGS Knowledge |
1.1(d) |
|
Contracts |
1.1(e) |
|
Permitted Encumbrances |
1.1(f) |
|
Reserved Liabilities |
1.1(g) |
|
System Maps |
4.3 |
|
Post Closing Consents |
4.4 |
|
HOLDINGS Required Consents |
4.5 |
|
Taxes |
4.6 |
|
Litigation |
4.9 |
|
Preferential Rights |
4.11 |
|
Real Property Matters |
4.12 |
|
Environmental Matters |
4.17 |
|
Subsidiaries |
4.18 |
|
Bank Accounts |
4.21 |
|
Annual Financial Statements |
5.4 |
|
MLP Required Consents |
6.9 |
|
Capital Projects |
10.2(e) |
|
Scheduled HOLDINGS Indemnified Matters |
Exhibits
|
|
|
A |
|
Form of JV LLC Agreement |
B |
|
Form of Subject Interests Assignment Agreement |
C |
|
Form of Certificate of Class D Units |
D |
|
Form of Amendment No. 2 |
E |
|
Form of Hedge Confirmation |
iii
CONTRIBUTION AGREEMENT
This Contribution Agreement (Agreement) is dated as of February 24, 2009 (the
Execution Date) and is by and among DCP LP Holdings, LLC, a Delaware limited liability
company (HOLDINGS), DCP Midstream GP, LP, a Delaware limited partnership (GP),
DCP Midstream, LLC, a Delaware limited liability company (MIDSTREAM), and DCP Midstream
Partners, LP, a Delaware limited partnership (MLP). HOLDINGS, GP, MIDSTREAM, and MLP are
sometimes referred to collectively herein as the Parties and individually as a Party.
R E C I T A L S
A. Pursuant to the Prior Contribution Agreement, MIDSTREAM, through HOLDINGS and GP conveyed
25% of the outstanding membership interests in DCP East Texas Holdings, LLC, a Delaware limited
liability company (the JV) to MLP.
B. Immediately prior to the date hereof, MIDSTREAM owned 75% of the outstanding membership
interests in the JV, and MLP owned 25% of the outstanding membership interests in the JV.
C. The JV owns all of the membership interests in FCV, ET and DETG, which collectively own and
operate certain midstream gathering, compression, dehydrating, processing and fractionating assets
located in Panola, Harrison, Shelby, and Rusk Counties, Texas, and Caddo and DeSoto Parishes,
Louisiana including the Former UP Fuels Properties and the Former Gulf South Properties, which are
generally depicted on the System Map (the East Texas System).
D. On the Closing Date, MIDSTREAM shall cause a 25.1% interest in the JV (the Subject
Interests) to be contributed to HOLDINGS and GP as capital contributions.
E. The Parties then desire that HOLDINGS and GP then contribute the Subject Interests to MLP
for the consideration and in accordance with the terms of this Agreement.
FOR GOOD AND VALUABLE CONSIDERATION, the receipt and sufficiency of which are hereby
acknowledged, MLP, GP, MIDSTREAM, and HOLDINGS agree as follows:
ARTICLE I
CERTAIN DEFINITIONS
1.1 Certain Defined Terms. Capitalized terms used herein and not defined elsewhere in
this Agreement shall have the meanings given such terms as is set forth below.
Affiliate means, when used with respect to a specified Person, any other Person
directly or indirectly controlling or controlled by or under direct or indirect common control with
the specified Person as of the time or for the time periods during which such determination is
made. For purposes of this definition control, when used with respect to any specified Person,
means the power to direct the management and policies of the Person, directly or indirectly,
1
whether through the ownership of voting securities, by contract or otherwise; and the terms
controlling and controlled have the meanings correlative to the foregoing. Notwithstanding the
foregoing, except for the JV, the term Affiliate when applied to (a) MLP shall not include
Spectra Energy Corp, a Delaware corporation, or ConocoPhillips, a Delaware corporation, or any
entities owned, directly or indirectly, by Spectra Energy Corp or ConocoPhillips, other than
entities owned, directly or indirectly, by MLP and GP and (b) HOLDINGS or GP shall not include MLP
or any entities owned, directly or indirectly, by MLP.
Amendment No. 2 shall mean Amendment No. 2 to that certain Second Amended and
Restated Agreement of Limited Partnership of MLP dated as the Effective Time and in the form of
Exhibit D hereto.
Annual Financial Statements shall have the meaning given such term in
Section 4.21(a).
Arbitral Dispute means any dispute, claim, counterclaim, demand, cause of action,
controversy and other matters in question arising out of or relating to this Agreement or the
alleged breach hereof, or in any way relating to the subject matter of this Agreement or the
relationship between the Parties created by this Agreement, regardless of whether (a) allegedly
extra-contractual in nature, (b) sounding in contract, tort, or otherwise, (c) provided for by
applicable Law or otherwise, or (d) seeking damages or any other relief, whether at Law, in equity,
or otherwise.
Arbitration Rules shall have the meaning given such term in Section 11.8(d).
Assets shall mean all of the following assets and properties of the JV (and its
respective Subsidiaries), except for the Excluded Assets:
(a) Personal Property. All tangible personal property of every kind and nature that
relates to the ownership, operation, use or maintenance of the Facilities, including meters,
valves, engines, field equipment, office equipment, fixtures, trailers, tools, instruments, spare
parts, machinery, computer equipment, telecommunications equipment, furniture, supplies and
materials that are located at the Facilities, and all hydrocarbon inventory at the Facilities,
including linefill (collectively the Personal Property);
(b) Real Property. All fee property, rights-of-way, easements, surface use
agreements, licenses and leases that relate to the ownership, operation, use or maintenance of the
Facilities, (collectively, the Real Property Interests), and all fixtures, buildings and
improvements located on or under such Real Property Interests;
(c) Permits. All assignable permits, licenses, certificates, orders, approvals,
authorizations, grants, consents, concessions, warrants, franchises and similar rights and
privileges which are necessary for, or are used or held for use primarily for or in connection
with, the ownership, use, operation or maintenance of the Assets (collectively, the
Permits);
(d) Contract Rights. All contracts that relate to the ownership, operation, use or
maintenance of the Assets, including all gathering, processing, balancing and other agreements for
the handling of natural gas or liquids, purchase and sales agreements, storage agreements,
2
transportation agreements, equipment leases, rental contracts, and service agreements
(collectively, the Contracts);
(e) Intellectual Property. All technical information, shop rights, designs, plans,
manuals, specifications and other proprietary and nonproprietary technology and data used in
connection with the ownership, operation, use or maintenance of the Assets (collectively, the
Intellectual Property);
(f) Facilities. All meter stations, gas processing plants, treaters, dehydration
units, compressor stations, fractionators, liquid handling facilities, platforms, warehouses, field
offices, control buildings, pipelines, tanks and other associated facilities that are used or held
for use in connection with the ownership, operation or maintenance of the East Texas System
(collectively, the Facilities);
(g) Books and Records. All contract, land, title, engineering, environmental,
operating, accounting, business, marketing, and other data, files, documents, instruments, notes,
correspondence, papers, ledgers, journals, reports, abstracts, surveys, maps, books, records and
studies which relate primarily to the Assets or which are used or held for use primarily in
connection with, the ownership, operation, use or maintenance of the Assets; provided, however,
such material shall not include (i) any proprietary data that is not primarily used in connection
with the continued ownership, use or operation of the Assets, (ii) any information subject to Third
Person confidentiality agreements for which a consent or waiver cannot be secured by HOLDINGS or GP
after reasonable efforts, (iii) any information which, if disclosed, would violate an
attorney-client privilege or would constitute a waiver of rights as to attorney work product or
attorney-client privileged communications, or (iv) any information relating primarily to the
Reserved Liabilities or any obligations for which HOLDINGS or GP is required to indemnify the MLP
Indemnitees pursuant to Section 10.2 (collectively, the Records); provided,
however, that MLP shall have the right to copy any of the information specified in clause (iv); and
(h) Incidental Rights. All of the following insofar as the same are attributable or
relate primarily to any of the Assets described in clauses (a) through (g): (i)
all purchase orders, invoices, storage or warehouse receipts, bills of lading, certificates of
title and documents, (ii) all keys, lock combinations, computer access codes and other devices or
information necessary to gain entry to and/or take possession of such Assets, (iii) all rights in
any confidentiality or nonuse agreements relating to the Assets, and (iv) the benefit of and right
to enforce all covenants, warranties, guarantees and suretyship agreements running in favor of the
Entities relating primarily to the Assets and all security provided primarily for payment or
performance thereof.
Assumed Obligations shall mean any and all obligations and liabilities with respect
to or arising out of (i) the JV LLC Agreement and attributable to the Subject Interests, (ii) the
ownership of the Subject Interests, and (iii) the Hedge.
Benefit Plan shall mean any of the following: (a) any employee welfare benefit plan
or employee pension benefit plan as defined in sections 3(1) and 3(2) of ERISA, and (b) any other
material employee benefit agreement or arrangement, including a deferred compensation plan,
3
incentive plan, bonus plan or arrangement, stock option plan, stock purchase plan, stock award
plan, golden parachute agreement, severance plan, dependent care plan, cafeteria plan, employee
assistance program, scholarship program, employment contract, retention incentive agreement,
non-competition agreement, consulting agreement, vacation policy, and other similar plan, agreement
and arrangement.
Business Day shall mean any day, other than Saturday and Sunday, on which
federally-insured commercial banks in Denver, Colorado are generally open for business and capable
of sending and receiving wire transfers.
Capital Projects shall have the meaning given such term in Section 6.9.
Casualty Loss shall mean, with respect to all or any portion of the Assets, any
destruction by fire, storm or other casualty, or any condemnation or taking or threatened
condemnation or taking, of all or any portion of the Assets.
Certificate of Common Units shall mean a certificate representing Units in the MLP
in the form of the attached Exhibit C.
Claim shall mean any demand, demand letter, claim or notice by a Third Person of
noncompliance or violation or Proceeding.
Claim Notice shall have the meaning given such term in Section 10.3(c).
Closing shall have the meaning given such term in Section 8.1.
Closing Date shall have the meaning given such term in Section 8.1.
Code shall mean the U.S. Internal Revenue Code of 1986, as amended.
Commercially Reasonable Efforts shall mean efforts which are reasonably within the
contemplation of the Parties on the date hereof, which are designed to enable a Party, directly or
indirectly, to satisfy a condition to, or otherwise assist in the consummation of, the transactions
contemplated by this Agreement and which do not require the performing Party to expend any funds or
assume liabilities other than expenditures and liabilities which are reasonable in nature and
amount in the context of the transactions contemplated by this Agreement.
Consideration has the meaning defined in Section 2.2.
Contracts shall have the meaning given such term in the definition of Assets.
Defensible Title shall mean, as to the Assets, such title to the Assets that vests
the applicable Entity with indefeasible title in and to the Assets free and clear of Liens other
than Permitted Encumbrances.
DETG shall mean DCP East Texas Gathering, LLC, a Delaware limited liability company.
4
East Texas Casualty Incident shall mean the fire and related property damage to the
Facilities that occurred on or about February 11, 2009.
East Texas System shall have the meaning given such term in the Recitals.
Effective Time shall mean 12:01 A.M. Denver time on April 1, 2009 (or, if the
Closing Date occurs later than April 1, 2009, 12:01 A.M. Denver time on the Closing Date).
Entities shall mean FCV, ET, DETG and the JV.
Environmental Law shall mean any and all Laws, statutes, ordinances, rules,
regulations, or orders of any Governmental Authority in existence at the Effective Time pertaining
to employee health, public safety, pollution or the protection of the environment or natural
resources or to Hazardous Materials in any and all jurisdictions in which the party in question
owns property or conducts business or in which the Assets are located, including the Clean Air Act,
the Comprehensive Environmental Response, Compensation, and Liability Act of 1980
(CERCLA), the Federal Water Pollution Control Act, the Occupational Safety and Health Act
of 1970 (to the extent relating to environmental matters), the Resource Conservation and Recovery
Act of 1976 (RCRA), the Safe Drinking Water Act, the Toxic Substances Control Act, the
Hazardous & Solid Waste Amendments Act of 1984, the Superfund Amendments and Reauthorization Act of
1986, the Hazardous Materials Transportation Act, the Oil Pollution Act of 1990, any state or local
Laws implementing or substantially equivalent to the foregoing federal Laws, and any state or local
Laws pertaining to the handling of oil and gas exploration, production, gathering, and processing
wastes or the use, maintenance, and closure of pits and impoundments.
Environmental Matter shall have the meaning given such term in Section
4.4(b).
ERISA shall mean the Employee Retirement Income Security Act of 1974, as amended.
ET shall mean EasTrans, LLC, a Delaware limited liability company.
Excluded Assets shall mean all of the following:
(a) Any deposits or pre-paid items attributable to the operation of the Assets not paid by or
on behalf of the JV;
(b) [Reserved];
(c) Claims for refund of or loss carry forwards with respect to (i) Taxes attributable
to the business of the Entities for any period prior to the Prior Contribution Agreement
Closing Date or (ii) any Taxes attributable to any of the Excluded Assets;
(d) All work product of HOLDINGS or its Affiliates attorneys, records relating to the
negotiation and consummation of the transactions contemplated hereby and documents that are
subject to a valid attorney client privilege;
5
(e) the real property, personal property, contracts, intellectual property, Permits,
office computers or other equipment (or any leases or licenses of the foregoing), if any,
that are listed on Schedule 1.1(a);
(f) All vehicles, and all leases for vehicles that relate to the ownership, operation,
use or maintenance of the Assets;
(g) All computer software that relates to the ownership, operation, use or maintenance
of the Assets that requires a consent to transfer;
(h) All rights and obligations under those certain swaps, futures and similar
derivative based transactions listed in Schedule 1.1(b);
(i) All office equipment and accessories (including computers) that relate to the
ownership, operation, use or maintenance of the Assets, other than that located at the
Facilities; and
(j) Without limiting the obligations under Sections 6.2, all rights to claim
coverage or benefits under any insurance policies or coverage applicable to the JV, the
Entities or the Assets, including self-insurance and insurance obtained through a captive
insurance carrier, but excluding any such rights to recover amounts that are included in the
calculation of Net Working Capital.
Exhibits shall mean any and/or all of the exhibits attached to and made a part of
this Agreement.
Execution Date shall have the meaning given such term in the opening paragraph of
this Agreement.
Existing JV Interests shall mean the Interests in the JV acquired by MLP pursuant to
the Prior Contribution Agreement.
Facilities shall have the meaning given such term within the definition of Assets.
FCV shall mean Fuels Cotton Valley Gathering, LLC, a Delaware limited liability
company.
Final Settlement Statement shall have the meaning given such term in Section
3.3.
Former Gulf South Properties shall mean the former Gulf South gathering facilities
located in Shelby, Panola and Harrison Counties, Texas and Caddo Parish, Louisiana, which are
generally depicted on the System Map, and which were acquired by DCP Midstream, LP or its
Affiliates on March 31, 2005.
Former UP Fuels Properties shall mean the former UP Fuels gathering and processing
facilities located in Panola, Shelby, Harrison and Rusk Counties, Texas, and Caddo and DeSoto
Parishes, Louisiana, which are generally depicted on the System Map, and which were acquired by DCP
Midstream, LP or its Affiliates on April 1, 1999.
6
GAAP means generally accepted accounting principles in the United States as of the
date hereof, consistently applied.
GP shall have the meaning given such term in the introductory paragraph.
Governmental Authorities shall mean (a) the United States of America or any state or
political subdivision thereof within the United States of America and (b) any court or any
governmental or administrative department, commission, board, bureau or agency of the United States
of America or of any state or political subdivision thereof within the United States of America.
HSR Act means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
Hazardous Materials shall mean: (a) any wastes, chemicals, materials or substances
defined or included in the definition of hazardous substances, hazardous materials, toxic
substances, solid wastes, pollutants, contaminants, or words of similar import, under any
Environmental Law; (b) any hydrocarbon or petroleum or component thereof, (including, without
limitation, crude oil, natural gas, natural gas liquids, or condensate that is not reasonably and
commercially recoverable; (c) oil and gas exploration or production wastes including produced
water; (d) radioactive materials (other than naturally occurring radioactive materials), friable
asbestos, mercury, lead based paints and polychlorinated biphenyls, (e) any other chemical,
material or substance, exposure to which is prohibited, limited or regulated by any Governmental
Authority; or (f) any regulated constituents or substances in concentrations or levels that exceed
numeric or risk-based standards established pursuant to Environmental Laws.
Hedge shall mean that certain financial swap transaction, with MLP as the fixed
price payor and HOLDINGS (or its Affiliate that is acceptable to MLP) as the floating price payor
for the period of April 1, 2009 through March 31, 2010,.
Hedge Confirmation shall mean the document used to evidence the Hedge in the form of
Exhibit E.
HOLDINGS shall have the meaning given such term in the introductory paragraph.
HOLDINGS Indemnitees shall have the meaning given such term in Section
10.1.
HOLDINGS Knowledge or the Knowledge of HOLDINGS or any similar term,
shall mean the actual knowledge of (a) any officer of HOLDINGS having a title of Vice President or
higher, and (b) the individuals listed on Schedule 1.1(c).
HOLDINGS Required Consents shall have meaning given such term in Section
4.4(a).
Indemnified Party or Indemnitee shall have the meaning given such term in
Section 10.4(a).
Indemnifying Party or Indemnitor shall have the meaning given such term in
Section 10.4(a).
7
Independent Accountants shall mean PricewaterhouseCoopers.
Inlet AFE shall have the meaning set forth in Schedule 6.9.
Intellectual Property shall have the meaning given such term in the definition of
Assets.
Interest Rate shall mean three (3) months LIBOR plus one-half of one percent (0.5%).
JV shall have the meaning given such term in the Recitals.
JV LLC Agreement shall mean the Amended and Restated Limited Liability Company
Agreement of DCP East Texas Holdings, LLC dated July 1, 2007, and from and after the Effective
Time, as amended and restated by the Second Amended and Restated Limited Liability Company
Agreement.
Laws shall mean all applicable statutes, laws (including common law), regulations,
rules, rulings, ordinances, orders, restrictions, requirements, writs, judgments, injunctions,
decrees and other official acts of or by any Governmental Authority.
Lien shall mean any lien, mortgage, pledge, claim, charge, security interest or
other encumbrance, option or defect on title.
LIBOR shall mean the British Bankers Association interbank offered rates as of
11:00 a.m. London time for deposits in Dollars that appear on the relevant page of the Reuters
service (currently page LIBOR01) or, if not available, on the relevant pages of any other service
(such as Bloomberg Financial Markets Service) that displays such British Bankers Association
rates.
Limited Partnership Agreement shall mean the Second Amended and Restated Agreement
of Limited Partnership of MLP dated as of November 1, 2006, as amended by Amendment No. 1 dated
April 11, 2008, and from and after the Effective Time, as amended by Amendment No. 2.
Loss or Losses shall mean any and all damages, demands, payments,
obligations, penalties, assessments, disbursements, claims, costs, liabilities, losses, causes of
action, and expenses, including interest, awards, judgments, settlements, fines, fees, costs of
defense and reasonable attorneys fees, costs of accountants, expert witnesses and other
professional advisors and costs of investigation and preparation of any kind or nature whatsoever.
Material Adverse Effect shall mean a single event, occurrence or fact, or series of
events, occurrences or facts, that, alone or together with all other events, occurrences or facts
(a) would have an adverse change in or effect on the Entities or the Assets (including the cost to
remedy, replace or obtain same) taken as a whole, in excess of $2,250,000 or (b) would result in
the prohibition or material delay in the consummation of the transactions contemplated by this
Agreement, excluding (in each case) matters that are generally industry-wide developments or
changes or effects resulting from changes in Law or general economic, regulatory or political
conditions.
8
Material Casualty Loss shall have the meaning given such term in Section
6.2.
Materiality Condition shall have the meaning given such term in Section
10.5.
MIDSTREAM shall have the meaning given such term in the introductory paragraph.
MLP shall have the meaning given such term in the introductory paragraph.
MLP Indemnitees shall have the meaning given such term in Section 10.2.
MLPs Knowledge or the Knowledge of MLP or any similar term, shall mean
the actual knowledge of any officer of MLP having a title of vice president or higher.
MLP Required Consents shall have the meaning given such term in Section 5.4.
Net Working Capital means, as to the JV, and determined as of the Effective Time, an
amount (which may be positive or negative) equal to (i) the total current assets of the JV and its
Subsidiaries minus (ii) the total current liabilities of the JV and its Subsidiaries, in
each case determined in accordance with GAAP.
New Capital Projects shall have the meaning given such term in Section
6.9(b).
Notice Period shall have the meaning given such term in Section 10.4(c).
Ordinary Course of Business shall mean the ordinary course of business consistent
with past practices.
Permits shall have the meaning given such term in the definition of Assets.
Permitted Encumbrances shall mean the following:
(a) the terms, conditions, restrictions, exceptions, reservations, limitations, and other
matters contained in any document creating the Real Property Interests, or in any Permit or
Contract;
(b) Liens for property Taxes and assessments that are not yet due and payable (or that are
being contested in good faith by appropriate Proceedings for which adequate reserves in accordance
with GAAP have been established on the books of account of the applicable Entity);
(c) mechanics, materialmens, repairmens and other statutory Liens arising in the Ordinary
Course of Business and securing obligations incurred prior to the Effective Time and (i) for which
adequate reserves in accordance with GAAP have been established on the books of account of the
applicable Entity, or (ii) that are not delinquent and that will be paid and discharged in the
Ordinary Course of Business or, if delinquent, that are being contested in good faith with any
action to foreclose on or attach any Assets on account thereof properly stayed and for which
adequate reserves in accordance with GAAP have been established on the books of account of the
applicable Entity;
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(d) utility easements, restrictive covenants, defects and irregularities in title,
encumbrances, exceptions and other matters that are of record that, singularly or in the aggregate,
will not materially interfere with the ownership, use or operation of the Assets to which they
pertain;
(e) required Third Person consents to assignment, preferential purchase rights and other
similar agreements with respect to which consents or waivers are obtained from the appropriate
Person for the transaction contemplated hereby prior to Closing or, as to which the appropriate
time for asserting such rights has expired as of the Closing without an exercise of such rights;
(f) any Post-Closing Consent;
(g) Liens created by MLP or its successors or assigns; and
(h) the Liens listed on Schedule 1.1(e).
Person shall mean any natural person, corporation, company, partnership (general or
limited), limited liability company, trust, joint venture, joint stock company, unincorporated
organization, or other entity or association.
Personal Property shall have the meaning given such term in the definition of
Assets.
Post-Closing Consents shall mean consents or approvals from, or filings with
Governmental Authorities or consents from railroads customarily obtained following the closing of
transactions involving the transfer of assets similar to those owned by the Entities, as listed on
Schedule 4.3.
Pre-Closing Tax Period shall mean, with respect to the Entities, any taxable period
ending on or prior to the Closing Date.
Preliminary Settlement Statement shall have the meaning given such term in
Section 3.2.
Prior Contribution Agreement shall mean that certain Contribution Agreement dated
May 23, 2007 among HOLDINGS, MIDSTREAM, GP and MLP.
Prior Contribution Agreement Closing Date shall mean July 1, 2007.
Proceeding shall mean any action, suit, claim, investigation, review or other
judicial or administrative proceeding, at Law or in equity, before or by any Governmental Authority
or arbitration or other dispute resolution proceeding.
Qualified Claims shall have the meaning given such term in Section
10.3(b)(iii).
Real Property Interests shall have the meaning given such term in the definition of
Assets.
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Records shall have the meaning given such term in the definition of Assets.
Reserved Liabilities shall mean Losses (but only to the extent not reflected in Net
Working Capital) with respect to:
(i) except for sales, transfer, use or similar Taxes that are due or should hereafter become
due (including penalty and interest thereon) by reason of creation of the JV and the conveyances
and transactions contemplated by this Agreement, 75% of the amount of Taxes with respect to the
Entities or the Assets to the extent related to periods prior to and including the Closing Date;
(ii) disposal of Hazardous Materials at offsite locations (a) which were delivered from the
East Texas System (excluding the Former Gulf South Properties) between April 1, 1999 and the
Closing Date and (b) which were delivered from the Former Gulf South Properties between March 31,
2005 and the Closing Date; provided, however, that the Reserved Liabilities shall only include 75%
of this form of Loss to the extent disposal occurred after the Prior Contribution Agreement Closing
Date; and
(iii) the Excluded Assets and Taxes related thereto; and
(iv) those matters, if any, described on Schedule 1.1(f).
Schedules shall mean any and/or all of the schedules attached to and made a part of
this Agreement.
SEC shall mean the U.S. Securities and Exchange Commission.
SEC Financial Statements shall mean collectively the Annual Financial Statements.
Securities Act shall mean the Securities Act of 1933, as amended.
Settlement Notice shall have the meaning given such term in Section 3.4.
Subject Interests shall have the meaning given such term in the Recitals.
Subject Interests Assignment Agreement shall mean the Assignment Agreement in
substantially the form of Exhibit B covering the conveyance of the Subject Interests by
HOLDINGS and GP to MLP.
Subsidiary means, with respect to any Person, (a) any corporation, of which a
majority of the total voting power of shares of stock entitled (without regard to the occurrence of
any contingency) to vote generally in the election of directors thereof is at the time owned or
controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that
Person or a combination thereof or (b) any limited liability company, partnership, association or
other business entity, of which a majority of the partnership or other similar ownership interests
thereof is at the time owned or controlled, directly or indirectly, by that Person or one or more
Subsidiaries of that Person or a combination thereof.
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System Map shall collectively mean the maps depicting the East Texas System, which
maps are attached as Schedules 1.1(g).
Tax or Taxes shall mean any federal, state, local or foreign income tax,
ad valorem tax, excise tax, sales tax, use tax, franchise tax, real or personal property tax,
transfer tax, gross receipts tax or other tax, assessment, duty, fee, levy or other governmental
charge, together with and including, any and all interest, fines, penalties, assessments, and
additions to Tax resulting from, relating to, or incurred in connection with any of those or any
contest or dispute thereof.
Tax Authority shall mean any Governmental Authority having jurisdiction over the
payment or reporting of any Tax.
Tax Benefits means the amount by which the Tax liability of the Indemnified Party or
any of its Affiliates for a taxable period is actually reduced (including by deduction, reduction
in income upon a sale, disposition or other similar transaction as a result of increased tax basis,
receipt of a refund of Taxes or use of a credit of Taxes) plus any related interest (net of Taxes
payable thereon) received from the relevant Tax Authority, as a result of the incurrence, accrual
or payment of any Loss or Tax with respect to which the indemnification payment is being made.
Tax Return shall mean any report, statement, form, return or other document or
information required to be supplied to a Tax Authority in connection with Taxes.
Third Person shall mean (i) any Person other than a Party or its Affiliates, and
(ii) any Governmental Authority.
Third Person Awards shall mean any actual recoveries from Third Persons by the
Indemnified Party (including from insurance and third-party indemnification) in connection with the
claim for which such party is also potentially liable.
Total Net Working Capital means the amount (which may be positive or negative) equal
to the product of the Net Working Capital multiplied by 25.1%.
Transaction Documents shall mean the JV LLC Agreement, Amendment No. 2, the Subject
Interests Assignment Agreement, such certificate or other documents as are necessary to transfer
the Units to HOLDINGS and GP pursuant to Section 2.2, the Hedge Confirmation, and any other
document related to the sale, transfer, assignment or conveyance of the Subject Interests to be
delivered at Closing.
Treasury Regulations shall mean regulations promulgated under the Code.
Units shall mean the Class D limited partnership interests issuable by MLP upon
execution of Amendment No. 2.
1.2 Other Definitional Provisions. As used in this Agreement, unless expressly stated
otherwise or the context requires otherwise, (a) all references to an Article, Section, or
subsection shall be to an Article, Section, or subsection of this Agreement, (b) the words this
Agreement, hereof, hereunder, herein, hereby, or words of similar import shall refer to
this Agreement as a whole and not to a particular Article, Section, subsection, clause or other
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subdivision hereof, (c) the words used herein shall include the masculine, feminine and neuter
gender, and the singular and the plural, (d) the word including means including, without
limitation and (e) the word day or days means a calendar day or days, unless otherwise denoted
as a Business Day.
1.3 Headings. The headings of the Articles and Sections of this Agreement and of the
Schedules and Exhibits are included for convenience only and shall not be deemed to constitute part
of this Agreement or to affect the construction or interpretation hereof or thereof.
1.4 Other Terms. Other terms may be defined elsewhere in the text of this Agreement
and shall have the meaning indicated throughout this Agreement.
ARTICLE II
CONTRIBUTION OF THE SUBJECT INTERESTS,
ISSUANCE OF THE UNITS AND CONSIDERATION
2.1 The Transaction. Upon the terms and subject to the conditions of this Agreement,
at the Closing, but effective for all purposes as of the Effective Time, HOLDINGS and GP shall
contribute to MLP the Subject Interests and the Hedge in exchange for the issuance of the
Consideration to HOLDINGS and GP pursuant to Section 2.2, and MLP shall assume and thereafter
timely perform and discharge in accordance with their respective terms, all Assumed Obligations.
2.2 Consideration. In consideration of HOLDINGS and GPs contribution of the Subject
Interests and the Hedge, MLP shall (i) issue and deliver to HOLDINGS and GP at the Closing one or
more certificates duly registered in the names of HOLDINGS and GP and representing in the case of
HOLDINGS, three million, two hundred thirty-one thousand, seven hundred fifty (3,231,750) Units and
in the case of GP, two hundred sixty-eight thousand, two hundred fifty (268,250) Units (such
3,500,000 Units being referred to herein collectively as, the Consideration) and (ii)
distribute an amount of cash to HOLDINGS and GP, in the aggregate, equal to (A) the Total Net
Working Capital and (B) 25.1% of amounts paid or accrued between the Execution Date and the Closing
by HOLDINGS or GP for New Capital Projects; provided, however, if the sum set forth in Section
2.2(ii) is a negative number, such value shall be paid by HOLDINGS and GP to MLP at the
Closing, and provided, further, that to the extent cash is distributed pursuant to Section 2.2(ii),
such amounts shall be allocated between and paid to HOLDINGS and GP in proportion to the number of
Units issued to each of them.
ARTICLE III
ADJUSTMENTS AND SETTLEMENT
3.1 Adjustments.
(a) The value of the Total Net Working Capital shall be subject to cash adjustments
pursuant to this Article III.
(b) The Parties shall use all Commercially Reasonable Efforts to agree upon the
adjustments set forth in this Article III, and to resolve any differences with
respect
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thereto. Except as provided herein, no adjustments shall be made after delivery of the
Final Settlement Statement.
3.2 Preliminary Settlement Statement. Not later than five (5) business days before
the Closing Date, and after consultation with MLP, HOLDINGS shall deliver to MLP a written
statement (the Preliminary Settlement Statement) setting forth the Total Net Working
Capital and each component therein, as determined in good faith by HOLDINGS that are described in
the definition thereof, with HOLDINGS calculation of such items in reasonable detail, based on
information then available to HOLDINGS. The Preliminary Settlement Statement shall also set forth
wire transfer instructions for the Closing payments. Payment of the Total Net Working Capital at
the Closing shall be based on the Preliminary Settlement Statement.
3.3 Final Settlement Statement. No later than ninety (90) days after the Closing Date
and after consultation with MLP, HOLDINGS shall deliver to MLP a revised settlement statement
showing in reasonable detail its calculation of the items described in the definition of Total Net
Working Capital along with other adjustments or payments contemplated in this Agreement (said
revised statement and the calculation thereof shall be referred to as the Final Settlement
Statement).
3.4 Dispute Procedures. The Final Settlement Statement shall become final and binding
on the Parties on the 45th day following the date the Final Settlement Statement is received by
MLP, unless prior to such date MLP delivers written notice to HOLDINGS of its disagreement with the
Final Settlement Statement (a Settlement Notice). Any Settlement Notice shall set forth
MLPs proposed changes to the Final Settlement Statement, including an explanation in reasonable
detail of the basis on which MLP proposes such changes. If MLP has timely delivered a Settlement
Notice, MLP and HOLDINGS shall use good faith efforts to reach written agreement on the disputed
items. If the disputed items have not been resolved by MLP and HOLDINGS by the 30th day following
HOLDINGS receipt of a Settlement Notice, any remaining disputed items shall be submitted to the
Independent Accountants for resolution within ten (10) Business Days after the end of the foregoing
30-day period. The fees and expenses of the Independent Accountants shall be borne fifty percent
(50%) by HOLDINGS and fifty percent (50%) by MLP. The Independent Accountants determination of
the disputed items shall be final and binding upon the Parties, and the Parties hereby waive any
and all rights to dispute such resolution in any manner, including in court, before an arbiter or
appeal.
3.5 Payments. If the final calculated amount as set forth in the Final Settlement
Statement exceeds the estimated calculated amount as set forth in the Preliminary Settlement
Statement, then MLP shall pay to HOLDINGS the amount of such excess, with interest at the Interest
Rate (calculated from the Closing Date). If the final calculated amount as set forth in the Final
Settlement Statement is less than the estimated calculated amount as set forth in the Preliminary
Settlement Statement, then HOLDINGS shall pay to MLP the amount of such excess, with interest at
the Interest Rate (calculated from the Closing Date). Any payment shall be made within three (3)
Business Days of the date the Final Settlement Statement becomes final pursuant to Section
3.4.
3.6 Access to Records. The Parties shall grant to each other full access to the
Records and relevant personnel to allow each of them to make evaluations under this Article
III.
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF HOLDINGS
HOLDINGS represents and warrants to MLP as follows:
4.1 Organization, Good Standing, and Authority.
(a) GP is a limited partnership duly formed, validly existing and in good standing
under the Laws of the State of Delaware. The execution and delivery of this Agreement and
the other Transaction Documents to which GP is a party and the consummation by GP of the
transactions contemplated herein and therein have been duly and validly authorized by all
necessary limited partnership action by GP. This Agreement has been duly executed and
delivered by GP. GP has all requisite limited partnership power and authority to enter into
and perform this Agreement and the other Transaction Documents to which it is a party, to
perform its obligations hereunder and thereunder and to carry out the transactions
contemplated herein and therein.
(b) Each of HOLDINGS and MIDSTREAM is a limited liability company duly formed, validly
existing and in good standing under the Laws of the State of Delaware. The execution and
delivery of this Agreement and the other Transaction Documents to which HOLDINGS and
MIDSTREAM is a party and the consummation by HOLDINGS and MIDSTREAM of the transactions
contemplated herein and therein have been duly and validly authorized by all necessary
limited liability company action by HOLDINGS and MIDSTREAM, respectively. This Agreement
has been duly executed and delivered by HOLDINGS and MIDSTREAM. Each of HOLDINGS and
MIDSTREAM has all requisite limited liability company power and authority to enter into and
perform this Agreement and the other Transaction Documents to which it is a party, to
perform its obligations hereunder and thereunder and to carry out the transactions
contemplated herein and therein.
(c) The JV, ET, FCV and DETG are limited liability companies duly formed, validly
existing and in good standing under the Laws of the State of Delaware and have all requisite
limited liability company power and authority to own or otherwise hold and operate its
assets. The execution and delivery of any Transaction Documents to which the JV is a party
and the consummation by the JV of the transactions contemplated herein and therein to which
it is a party have been duly and validly authorized by all necessary limited liability
company action by the JV, ET, FCV and/or DETG (as the case may be).
4.2 Enforceability. This Agreement constitutes and, upon execution of and delivery by
HOLDINGS, GP and MIDSTREAM of the other Transaction Documents to which it is a party, such
Transaction Documents will constitute, valid and binding obligations of HOLDINGS, GP and MIDSTREAM,
enforceable against such Parties in accordance with their terms, subject to applicable bankruptcy,
insolvency, reorganization, moratorium and other similar Laws affecting creditors rights generally
and general principles of equity.
4.3 No Conflicts. The execution, delivery and performance by HOLDINGS, GP and
MIDSTREAM of this Agreement, and the execution, delivery and performance by HOLDINGS,
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GP and MIDSTREAM of the other Transaction Documents to which it is a party and the
consummation of the transactions contemplated hereby or thereby, will not:
(a) Provided all of HOLDINGS Required Consents and Post Closing Consents have been
obtained, conflict with, constitute a breach, violation or termination of, give rise to any
right of termination, cancellation or acceleration of or result in the loss of any right or
benefit under, any agreements to which HOLDINGS, GP, MIDSTREAM or the Entities is a party or
by which any of them, the Subject Interests or the Assets are bound;
(b) Conflict with or violate the limited liability company agreements of MIDSTREAM, JV,
DETG, FCV, HOLDINGS, GP or ET; and
(c) Provided that all of HOLDINGS Required Consents and Post Closing Consents have
been obtained, violate any Law applicable to HOLDINGS, GP, MIDSTREAM or the Entities or the
Assets.
4.4 Consents, Approvals, Authorizations and Governmental Regulations.
(a) Except (i) for Post-Closing Consents, (ii) as set forth in Schedule 4.4 and
(iii) as may be required under the HSR Act (the items described in clauses (ii) and (iii)
being collectively referred to as the HOLDINGS Required Consents; no order,
consent, waiver, permission, authorization or approval of, or exemption by, or the giving of
notice to or the registration or filing with any Third Person, is necessary for HOLDINGS, GP
or MIDSTREAM to execute, deliver and perform this Agreement or for HOLDINGS, GP or MIDSTREAM
to execute, deliver and perform the other Transaction Documents to which it is a party.
(b) Except as set forth in Schedule 4.4, (i), all material permits, licenses,
certificates, orders, approvals, authorizations, grants, consents, concessions, warrants,
franchises and similar rights and privileges, of all Governmental Authorities required or
necessary for the Entities to own and operate its Assets in the places and in the manner
currently owned or operated, have been obtained, and are in full force and effect, (ii)
HOLDINGS and its Affiliates have received no written notification concerning, and there are
no violations that are in existence with respect to the permits and (iii) no Proceeding is
pending or threatened with respect to the revocation or limitation of any of the permits.
Notwithstanding anything herein to the contrary, the provisions of this Section
4.4(b) shall not relate to or cover any matter relating to or arising out of any
Environmental Laws (an Environmental Matter), which shall be governed by
Section 4.12.
4.5 Taxes. Except as set forth in Schedule 4.5:
(a) JV has not and will not on or prior to the Closing Date, file an election under
Treasury Regulation §301.7701-3 to be classified as a corporation for U.S. federal income
tax purposes. Since the date of their formation until Closing, DETG, FCV and ET have been
and will be business entities that will be disregarded for federal Tax purposes under
Treasury Regulation §§301.7701-2 and -3;
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(b) Except with respect to ad valorem Taxes for the year in which Closing occurs, all
Taxes due and owing or claimed to be due and owing (whether such claim is asserted before or
after the Effective Time) from or against any Entity relating to the Assets, or the
operation thereof, prior to the Effective Time have been or will be timely paid in full by,
for or on behalf or with respect to the Entity owing such Tax;
(c) All withholding Tax and Tax deposit requirements imposed on HOLDINGS, the Entities,
and applicable to the Assets, or the operation thereof, for any and all periods or portions
thereof ending prior to the Effective Time have been or will be timely satisfied in full by
for or on behalf or with respect to the Entity owing such Tax;
(d) All Tax Returns that are required to be timely filed for, by, on behalf of or with
respect to the Entities, before the Effective Time have been or will be filed with the
appropriate Governmental Authority; all Taxes shown to be due and payable on such Tax
Returns have been or will be paid in full by, for or on behalf or with respect to the Entity
owing such Tax;
(e) None of the Entities is under Tax audit or Tax examination by any Governmental
Authority. There are no Claims now pending or, to the Knowledge of HOLDINGS, threatened
against the Entities with respect to any Tax or any matters under discussion with any
Governmental Authority relating to any Tax;
(f) None of the Entities (i) has agreed to make, nor is required to make, any
adjustment under Section 481 of the Code or any comparable provision of state, local or
foreign Law by reason of a change in accounting method or otherwise, and (ii) is a party to
or bound by (or will become a party to or bound by) any Tax sharing, Tax indemnity or Tax
allocation agreement; and
(g) The JV has made an election under Section 754 of the Code.
4.6 Litigation; Compliance with Laws.
(a) There is no injunction, restraining order or Proceeding pending against HOLDINGS,
GP, MIDSTREAM or the Entities that restrains or prohibits the consummation of the
transactions contemplated by this Agreement.
(b) Except for the litigation and Claims identified on Schedule 4.6, there is
no written Claim, investigation or examination pending, or to the Knowledge of HOLDINGS and
GP, threatened, against or affecting the Entities (or their respective assets) before or by
any Third Person.
(c) To HOLDINGS Knowledge, the Assets have been owned and operated in compliance with
applicable Laws, except for any non-compliance which has been timely brought into compliance
therewith. Notwithstanding anything herein to the contrary, the provisions of this
Section 4.6(c) shall not relate to or cover any Environmental Matters, which shall
be governed by Section 4.12.
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4.7 Contracts. All of the Contracts that are material to the business of the
Entities, taken as a whole, are listed on Schedule 1.1(d), with the exception of interests
in real property. The Entities are not in default and there is no event or circumstance that with
notice, or lapse of time or both, would constitute an event of default by the applicable Entity
under the terms of the Contracts. All of the Contracts of the Entities are in full force and
effect and to HOLDINGS Knowledge, no counter-party to any of the Contracts is in default under the
terms of such Contracts. Schedule 1.1(d) lists each Contract that:
(a) expressly obligates an Entity to pay an amount of $500,000 (to the 100% interest)
or more and has not been fully performed as of the date hereof;
(b) expressly restricts the ability of an Entity to compete or otherwise to conduct its
business in any manner or place;
(c) provides for the sale of products or the provision of services (for a term greater
than a year) for amounts in excess of $500,000 (to the 100% interest and including
outstanding offers or quotes which by acceptance would create such a Contract) and which
have not been fully performed as of the date hereof;
(d) provides a right of first refusal or other restrictive right that limits the
ability to transfer, sell or assign an interest in an asset or an equity interest in a
Person;
(e) is a master agreement, swap, derivative, option, future or similar type Contract or
any open agreement or position thereunder;
(f) is with any current or former employee, officer, director or consultant of HOLDINGS
or an Entity or their respective Affiliates;
(g) is an inter-company agreement;
(h) is with any labor union or association;
(i) is a partnership or joint venture agreement with a Third Person in which one of
HOLDINGS or an Entity or their respective Affiliates is a party or by which any of them are
bound;
(j) is an agreement with a consideration in excess of $500,000 (to the 100% interest)
by an Entity to purchase or sell any assets (other than inventory in the Ordinary Course of
Business), businesses, capital stock or other debt or equity securities of any Person; or
(k) is an agreement with a consideration in excess of $500,000 (to the 100% interest)
involving the merger, consolidation, purchase, sale, transfer or other disposition of
interests in real property, capital stock or other debt or equity securities of any Person
prior to Closing.
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4.8 Title to Assets; Intellectual Property. Except for the Permitted Encumbrances,
each of the Entities has Defensible Title to those of the Assets that it operates, free and clear
of all Liens, and:
(a) none of HOLDINGS or the Entities has received any written notice of infringement,
misappropriation or conflict with respect to Intellectual Property from any Person with
respect to the ownership, use or operation of the Assets; and
(b) the ownership, use and operation of the Assets have not infringed, misappropriated
or otherwise conflicted with any patents, patent applications, patent rights, trademarks,
trademark applications, service marks, service mark applications, copyrights, trade names,
unregistered copyrights or trade secrets of any other Person.
4.9 Preferential Rights to Purchase. Except as listed in Schedule 4.9, there
are no preferential or similar rights to purchase any portion of the Entities or Assets that will
be triggered by this Agreement or the transactions contemplated herein.
4.10 Brokers or Finders Fees. No investment banker, broker, finder or other Person
is entitled to any brokerage or finders fee or similar commission in respect thereof based in any
way on agreements, arrangements or understandings made by or on behalf of HOLDINGS or any of its
Affiliates.
4.11 Compliance with Property Instruments. To HOLDINGS Knowledge and except as set
forth in Schedule 4.11, (a) all of the instruments creating the Real Property Interests are
presently valid, subsisting and in full force and effect; (b) there are no violations, defaults or
breaches thereunder, or existing facts or circumstances which upon notice or the passage of time or
both will constitute a violation, default or breach thereunder; and (c) the Assets are currently
being operated and maintained in compliance with all terms and provisions of the instruments
creating the Real Property Interests. None of HOLDINGS or its Affiliates has received or given any
written notice of default or claimed default under any such instruments and is not participating in
any negotiations regarding any material modifications thereof.
4.12 Environmental Matters. Except as set forth in Schedule 4.12:
(a) to HOLDINGS Knowledge, HOLDINGS and its Affiliates have not caused or allowed the
generation, use, treatment, manufacture, storage, or disposal of Hazardous Materials at, on
or from the Assets, except in accordance with all applicable Environmental Laws;
(b) to HOLDINGS Knowledge, there has been no release of any Hazardous Materials at,
on, from or underlying any of the Assets other than such releases that (i) are not required
to be reported to a Governmental Authority, (ii) have been reported to the appropriate
Governmental Authority or (iii) were in compliance with applicable Environmental Laws;
(c) to HOLDINGS Knowledge, the Entities have secured all permits required under
Environmental Laws for the ownership, use and operation of the Assets and the Entities are
in compliance with such permits;
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(d) HOLDINGS and its Affiliates have not received written inquiry or notice of any
actual or threatened Claim related to or arising under any Environmental Law relating to the
Assets;
(e) none of HOLDINGS or the Entities is currently operating or required to be operating
any of the Assets under any compliance order, a decree or agreement, any consent decree or
order, or corrective action decree or order issued by or entered into with any Governmental
Authority under any Environmental Law or any Law regarding health or safety in the work
place;
(f) to HOLDINGS Knowledge, the Entities have owned, used and operated the Assets in
compliance with Environmental Laws, except for any non-compliance which has been remediated
and brought into compliance with Environmental Laws; and
(g) to HOLDINGS Knowledge, none of the off-site locations where Hazardous Materials
from any of the Assets have been transported, stored, treated, recycled, disposed of or
released has been designated as a facility that is subject to a Claim under any
Environmental Laws.
4.13 Employee Matters. At no time prior to the Effective Time will the Entities have
had any employees.
4.14 Benefit Plan Liabilities. At no time prior to the Effective Time will the
Entities have maintained any Benefit Plans. At the Effective Time, the Entities shall have no
liability with respect to any Benefit Plans.
4.15 No Foreign Person. HOLDINGS is not a foreign person as defined in Section 1445
of the Code and in any regulations promulgated thereunder.
4.16 Capitalization of the Subject Interests.
(a) The Subject Interests (i) constitute 25.1% of the outstanding ownership interests
in the JV, (ii) were duly authorized, validly issued, fully paid and non-assessable and
(iii) were not issued in violation of any pre-emptive rights.
(b) HOLDINGS and GP, as applicable, has good and valid title to the Subject Interests
conveyed by each of them and, except as provided or created by its limited liability company
agreement or other organizational or governance documents, the Securities Act or applicable
securities Laws, the Subject Interests are free and clear of any (i) restrictions on
transfer, Taxes, Liens, Claims, or Proceedings or (ii) encumbrances, options, warrants,
purchase rights, contracts, commitments, equities or demands to the extent any of the same
contain or create any right to acquire all or any right in or to the Subject Interests.
(c) There are no existing rights, agreements or commitments of any character obligating
the Entities to issue, transfer or sell any additional ownership rights or interests or any
other securities (debt, equity or otherwise) convertible into or exchangeable for
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such ownership rights or interests or repurchase, redeem or otherwise acquire any such
interest.
4.17 Subsidiaries and Other Equity Interests. As of Closing, the JV will not have any
Subsidiaries or own, directly or indirectly, any equity interest in any other Person except the
limited liability company interests listed on Schedule 4.17.
4.18 Bank Accounts. Except as set forth on Schedule 4.18, FCV, DETG and ET
(and as of Closing, the JV), have no accounts or safe-deposit boxes with banks, trust companies,
savings and loan associations, or other financial institutions.
4.19 [Reserved].
4.20 Investment Intent. HOLDINGS and GP is acquiring the Units for its own account,
and not with a view to, or for sale in connection with, the distribution thereof in violation of
state or federal Law. HOLDINGS and GP acknowledges that the Units have not been registered under
the Securities Act or the securities Laws of any state and neither HOLDINGS nor GP has any
obligation or right to register the Units except as set forth in the Limited Partnership Agreement.
Without such registration, the Units may not be sold, pledged, hypothecated or otherwise
transferred unless it is determined that registration is not required. HOLDINGS, itself or through
its officers, employees or agents, has sufficient knowledge and experience in financial and
business matters to be capable of evaluating the merits and risks of an investment such as an
investment in the Units, and HOLDINGS, either alone or through its officers, employees or agents,
has evaluated the merits and risks of the investment in the Units.
4.21 Financial Statements; Internal Controls; Undisclosed Liabilities. To HOLDINGS
Knowledge:
(a) Schedule 4.21 sets forth a true and complete copy of the [unaudited]
consolidated balance sheet as of December 31, 2008, and the unaudited consolidated statement
of changes in MLPs equity, the unaudited consolidated statement of operations, and
unaudited consolidated statement of cash flow for the twelve months ended December 31, 2008;
and the audited consolidated balance sheet as of December 31, 2007, and the audited
consolidated statement of changes in MLPs equity, the audited consolidated statement of
operations, and audited consolidated statement of cash flow for the twelve months ended
December 31, 2007 for the business of the JV (the Annual Financial Statements).
The Annual Financial Statements have been prepared in accordance with the requirements of
Regulation S-X adopted by the SEC.
(b) There are no liabilities or obligations of the JV (whether known or unknown and
whether accrued, absolute, contingent or otherwise) and there are no facts or circumstances
that would reasonably be expected to result in any such liabilities or obligations, other
than (i) liabilities or obligations disclosed, reflected or reserved against in the Annual
Financial Statements, and (ii) current liabilities incurred in the Ordinary Course of
Business since December 31, 2008.
4.22 No Other Representations or Warranties; Schedules. HOLDINGS makes no other
express or implied representation or warranty with respect to the Entities or any of their
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respective Affiliates, the Assets or the transactions contemplated by this Agreement, and
disclaims any other representations or warranties. The disclosure of any matter or item in any
schedule to this Agreement shall not be deemed to constitute an acknowledgment that any such matter
is required to be disclosed.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF MLP
MLP hereby represents and warrants to HOLDINGS:
5.1 Organization, Good Standing, and Authorization. MLP is a limited partnership duly
formed, validly existing and in good standing under the Laws of the State of Delaware. MLP has all
requisite limited partnership power and authority to enter into and perform this Agreement and the
Transaction Documents to which it is a party, to perform its obligations hereunder and thereunder
and to carry out the transactions contemplated herein and therein. The execution and delivery of
this Agreement and the Transaction Documents to which it is a party and the consummation by MLP of
the transactions contemplated herein have been duly and validly authorized by all necessary limited
partnership action by MLP. This Agreement has been duly executed and delivered by MLP.
5.2 Enforceability. This Agreement constitutes, and upon execution and delivery of
the Transaction Documents to which MLP is a party, such Transaction Documents will constitute,
valid and binding obligations of MLP, enforceable against MLP in accordance with their terms,
subject to applicable bankruptcy, insolvency, reorganization, moratorium and other similar Laws
affecting creditors rights generally and general principles of equity.
5.3 No Conflicts. The execution, delivery and performance by MLP of this Agreement
and the Transaction Documents and the consummation of the transactions contemplated hereby or
thereby, will not:
(a) provided that any MLP Required Consents and Post-Closing Consents have been
obtained, conflict with, constitute a breach, violation or termination of, give rise to any
right of termination, cancellation or acceleration of or result in the loss of any right or
benefit under, any agreement to which MLP is a party;
(b) conflict with or violate the Limited Partnership Agreement or result in the
creation of a Lien on the Units; or
(c) provided that all of the MLP Required Consents and Post Closing Consents have been
obtained, violate any Law applicable to MLP.
5.4 Consents, Approvals, Authorizations and Governmental Regulations. Except (i) for
Post-Closing Consents, and (ii) as set forth in Schedule 5.4 and (iii) as may be required
under the HSR Act (the items described in clauses (ii) and (iii) being collectively referred to as
the MLP Required Consents), no order, consent, waiver, permission, authorization or
approval of, or exemption by, or the giving of notice to or registration or filing with, any Third
Person, is necessary for MLP to execute, deliver and perform this Agreement or the Transaction
Documents to which it will be a party.
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5.5 Litigation. There is no injunction, restraining order or Proceeding pending
against MLP that restrains or prohibits the consummation of the transactions contemplated by this
Agreement.
5.6 Independent Investigation. MLP is knowledgeable in the business of owning and
operating natural gas and natural gas liquids facilities and has had access to the Assets, the
representatives of HOLDINGS and its Affiliates, and to the records of HOLDINGS and its Affiliates
with respect to the Assets. MLP ACKNOWLEDGES THAT THE ASSETS ARE IN THEIR AS IS, WHERE IS
CONDITION AND STATE OF REPAIR, AND WITH ALL FAULTS AND DEFECTS, AND THAT, EXCEPT AS EXPRESSLY SET
OUT IN THIS AGREEMENT, HOLDINGS HAS MADE NO REPRESENTATION OR WARRANTY OF ANY KIND OR NATURE,
EXPRESS, IMPLIED OR STATUTORY, INCLUDING, BUT NOT LIMITED TO, WARRANTIES OF MARKETABILITY, QUALITY,
CONDITION, CONFORMITY TO SAMPLES, MERCHANTABILITY, AND/OR FITNESS FOR A PARTICULAR PURPOSE, ALL OF
WHICH ARE EXPRESSLY DISCLAIMED BY HOLDINGS AND EXCEPT AS SET FORTH IN THIS AGREEMENT, WAIVED BY
MLP. MLP FURTHER ACKNOWLEDGES THAT: (I) THE ASSETS HAVE BEEN USED FOR NATURAL GAS AND NATURAL GAS
LIQUIDS OPERATIONS AND PHYSICAL CHANGES IN THE ASSETS AND IN THE LANDS BURDENED THEREBY MAY HAVE
OCCURRED AS A RESULT OF SUCH USES; (II) THE ASSETS MAY INCLUDE BURIED PIPELINES AND OTHER
EQUIPMENT, THE LOCATIONS OF WHICH MAY NOT BE KNOWN BY HOLDINGS OR READILY APPARENT BY A PHYSICAL
INSPECTION OF THE ASSETS OR THE LANDS BURDENED THEREBY; (III) MLP SHALL HAVE INSPECTED PRIOR TO
CLOSING, OR SHALL BE DEEMED TO HAVE WAIVED ITS RIGHTS TO INSPECT, THE ASSETS AND THE ASSOCIATED
PREMISES, AND SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL CONDITION, AND THAT MLP
SHALL, SUBJECT TO THE OTHER PROVISIONS OF THIS AGREEMENT, ACCEPT ALL OF THE SAME IN THEIR AS IS,
WHERE IS CONDITION AND STATE OF REPAIR, AND WITH ALL FAULTS AND DEFECTS, INCLUDING, BUT NOT
LIMITED TO, THE PRESENCE OF MAN-MADE MATERIAL FIBERS AND THE PRESENCE, RELEASE OR DISPOSAL OF
HAZARDOUS MATERIALS. EXCEPT AS EXPRESSLY SET OUT IN THIS AGREEMENT, HOLDINGS MAKES NO
REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED OR STATUTORY, AS TO (A) THE ACCURACY OR COMPLETENESS
OF ANY DATA OR RECORDS DELIVERED TO MLP WITH RESPECT TO THE INTERESTS, INCLUDING, WITHOUT
LIMITATION, ANY DESCRIPTION OF THE INTERESTS, PRICING ASSUMPTIONS, QUALITY OR QUANTITY OF THE
INTERESTS, FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT OR (B) FUTURE VOLUMES OF HYDROCARBONS OR
OTHER PRODUCTS TRANSPORTED, TREATED, STORED OR PROCESSED THROUGH OR AT THE ASSETS. With respect to
any projection or forecast delivered by or on behalf of HOLDINGS or its Affiliates to MLP, MLP
acknowledges that (i) there are uncertainties inherent in attempting to make such projections and
forecasts, (ii) MLP is familiar with such uncertainties, (iii) MLP is taking full responsibility
for making its own evaluation of the adequacy and accuracy of all such projections and forecasts
furnished to MLP and (iv) MLP will not have a claim against HOLDINGS or any of its advisors or
Affiliates with respect to such projections or forecasts.
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5.7 Brokers or Finders Fees. No investment banker, broker, finder or other Person
is entitled to any brokerage or finders fee or similar commission in respect thereof based in any
way on agreements, arrangements or understandings made by or on behalf of MLP or any of its
Affiliates which is, or following the Closing would be, an obligation of HOLDINGS or any of its
Affiliates.
5.8 Investment Intent. MLP is acquiring the Subject Interests for its own account,
and not with a view to, or for sale in connection with, the distribution thereof in violation of
state or federal Law. MLP acknowledges that the Subject Interests have not been registered under
the Securities Act or the securities Laws of any state and neither HOLDINGS nor any of its
Affiliates has any obligation to register the Subject Interests. Without such registration, the
Subject Interests may not be sold, pledged, hypothecated or otherwise transferred unless it is
determined that registration is not required. MLP, itself or through its officers, employees or
agents, has sufficient knowledge and experience in financial and business matters to be capable of
evaluating the merits and risks of an investment such as an investment in the Subject Interests,
and MLP, either alone or through its officers, employees or agents, has evaluated the merits and
risks of the investment in the Subject Interests.
5.9 Available Funds. MLP will have at Closing, sufficient cash to enable it to make
payment in immediately available funds of the cash amount specified in Section 2.2(ii) when due and
any other amounts to be paid by it hereunder.
ARTICLE VI
COVENANTS AND ACCESS
6.1 Conduct of Business. HOLDINGS and MIDSTREAM each covenants and agrees that from
and after the execution of this Agreement and until the Closing:
(a) Without the prior written consent of MLP, (i) HOLDINGS will not, and will not
permit the Entities to sell, transfer, assign, convey or otherwise dispose of any Assets
other than (A) the transfer of the Excluded Assets; (B) the sale of inventory in the
Ordinary Course of Business or (C) the sale or other disposition of equipment or other
Personal Property which is replaced with equipment or other Personal Property of
comparable or better value and utility; (ii) except for the existing Capital Projects,
modify in any respect the East Texas System that will require a capital expenditure in
excess of $1,000,000 (as to the 100% interest); (iii) make any adverse change in its
sales, credit or collection terms and conditions relating to the Assets; (iv) do any act
or omit to do any act which will cause a material breach in any Contract; or (v) unless
disputed in good faith, fail to pay when due all amounts owed under the Contracts;
(b) HOLDINGS will not allow the Entities to create or permit the creation of any
Lien on any Asset other than Permitted Encumbrances;
(c) If HOLDINGS becomes aware of any event or development that it reasonably
believes is likely to cause a material breach or default hereunder or to have a Material
Adverse Effect, it will give prompt written notice to MLP; and
(d) HOLDINGS will and will cause the Entities to:
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(i) maintain and operate the Assets in the Ordinary Course of Business,
including regular scheduled maintenance plans and capital expenditures, and pay or
cause to be paid all costs and expenses in connection therewith when due;
(ii) carry on its business in respect of the Assets in substantially the same
manner as it has heretofore;
(iii) use reasonable efforts to preserve its business in respect of the Assets
intact, to keep available the services of the employees involved in the conduct of
such business and to preserve the goodwill of customers having business relations
with the applicable Entities in respect of the Assets, in each case, in all material
respects;
(iv) not abandon any of the Assets or liquidate, dissolve, recapitalize or
otherwise wind up its business;
(v) comply in all material respects with all of the rules, regulations and
orders of any Governmental Authority applicable to the Assets;
(vi) timely file, properly and accurately make in all material respects all
reports and filings required to be filed with the appropriate Governmental
Authority; and
(vii) pay all Taxes with respect to the Assets which come due and payable prior
to the Closing Date;
(viii) not make, amend or revoke any material election with respect to Taxes;
(ix) not amend its organizational documents;
(x) not make any material change in any method of accounting or accounting
principles, practices or policies, other than those required by GAAP;
(xi) not issue or sell any equity interests, notes, bonds or other securities
or incur, assume or guarantee any indebtedness for borrowed money, or any option,
warrant or right to acquire same;
(xii) not (A) merge or consolidate with any Person; or (B) make any loan to any
Person (other than extensions of credit to customers in the Ordinary Course of
Business and inter-company loans under DCP Midstream, LLCs cash management system);
and
(xiii) maintain in full force and effect insurance policies covering the
Assets.
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(xiv) with respect to the Contracts, not enter into any financial derivatives
that would be Assumed Obligations unless the same are in compliance with MIDSTREAMs
risk management guidelines.
6.2 Casualty Loss.
(a) HOLDINGS shall promptly notify MLP of any Casualty Loss of which HOLDINGS becomes
aware prior to the Closing. If a Casualty Loss, other than the East Texas Casualty Incident
(addressed in (c) below), occurs and such Casualty Loss would reasonably be expected to have
a Material Adverse Effect (a Material Casualty Loss), HOLDINGS shall have the
right to extend the Closing Date for up to forty-five (45) days for the purpose of repairing
or replacing the Assets destroyed or damaged by the Material Casualty Loss to the reasonable
satisfaction of MLP. If HOLDINGS does not repair or replace the Assets destroyed or damaged
by the Material Casualty Loss prior to the Closing to the reasonable satisfaction of MLP and
the Parties are unable to agree on a value to compensate MLP for the Material Casualty Loss,
MLP may terminate this Agreement upon fifteen (15) days written notice to HOLDINGS.
(b) If this Agreement is not terminated by MLP as provided in subsection (a), MLPs
sole remedy with respect to any Casualty Loss in respect of Assets which are not repaired or
replaced prior to the Closing to the reasonable satisfaction of MLP (but only to the extent
not reflected in Net Working Capital) is to accept a value estimated by HOLDINGS and agreed
to by MLP to be equal to 25.1% of the cost to repair or replace the Assets of any Entity
affected by the Casualty Loss, as applicable; provided that (A) if the Parties
cannot agree, then the Closing shall occur and either Party may submit the determination of
the costs of the Casualty Loss for resolution pursuant to Section 11.8; and (B) with
respect to any Casualty Loss, any insurance, condemnation or taking proceeds shall become
25.1% the sole property of HOLDINGS and GP, and 74.9% the sole property of the JV, to be
managed pursuant to the terms of the JV LLC Agreement, and each Party shall execute such
assignments, releases, resolutions or other documents as may be necessary to vest such
proceeds in the persons and percentages set forth above.
(c) As to the East Texas Casualty Incident, HOLDINGS shall pay the costs and expenses
attributable to the Subject Interests as necessary to repair and replace the damaged
Facilities caused by the East Texas Casualty Incident prior to the Closing, to the
reasonable satisfaction of MLP. In consideration of HOLDINGS obligation to pay the costs
and expenses attributable to the Subject Interests to repair and replace the Facilities
damaged by the East Texas Casualty Incident, any and all insurance proceeds attributable to
the Subject Interests that may be payable to the JV, MLP or any of their Affiliates in
respect of any claims made regarding the East Texas Casualty Incident (including without
limitation, property loss policy proceeds and business interruption policy proceeds) shall
be the sole property of HOLDINGS, and each Party shall execute such assignments, releases,
resolutions or other documents as may be necessary to vest such proceeds in the persons and
percentages set forth above. HOLDINGS shall have the right to extend the Closing Date for
up to forty-five (45) days for the purpose of repairing or replacing the Facilities
destroyed or damaged by the East Texas Casualty Incident. If HOLDINGS does not repair or
replace the Assets destroyed or damaged by the East Texas Casualty
26
Incident prior to the Closing to the reasonable satisfaction of MLP, and the Parties are
unable to agree on a value to compensate MLP for the East Texas Casualty Incidents effect
on the Subject Interests, then MLP may terminate this Agreement upon fifteen (15) days
written notice to HOLDINGS.
6.3 Access, Information and Access Indemnity.
(a) Prior to Closing, HOLDINGS will make available at HOLDINGS offices to MLP and
MLPs authorized representatives for examination as MLP may reasonably request, all Records;
provided, however, such material shall not include (i) any proprietary data which relates to
another business of HOLDINGS or its Affiliates and is not primarily used in connection with
the continued ownership, use or operation of the Assets, (ii) any information subject to
Third Person confidentiality agreements for which a consent or waiver cannot be secured by
HOLDINGS or its Affiliates after reasonable efforts, or (iii) any information which, if
disclosed, would violate an attorney-client privilege or would constitute a waiver of rights
as to attorney work product or attorney-client privileged communications.
(b) Subject to subsection (a) above, HOLDINGS shall permit MLP and MLPs
authorized representatives to consult with employees of HOLDINGS and its Affiliates during
the business hours of 8:00 a.m. to 5:00 p.m. (local time), Monday through Friday and to
conduct, at MLPs sole risk and expense, inspections and inventories of the Assets and to
examine all Records over which HOLDINGS and its Affiliates have control. HOLDINGS shall
also coordinate, in advance, with MLP to allow site visits and inspections at the field
sites on Saturdays unless operational conditions would reasonably prohibit such access.
(c) MLP SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD THE HOLDINGS INDEMNITEES HARMLESS
FROM AND AGAINST ANY AND ALL CLAIMS AND LOSSES OCCURRING ON OR TO THE ASSETS CAUSED BY THE
ACTS OR OMISSIONS OF MLP, MLPS AFFILIATES OR ANY PERSON ACTING ON MLPS OR ITS AFFILIATES
BEHALF IN CONNECTION WITH ANY DUE DILIGENCE CONDUCTED PURSUANT TO OR IN CONNECTION WITH THIS
AGREEMENT PRIOR TO CLOSING, INCLUDING ANY SITE VISITS AND ENVIRONMENTAL SAMPLING; PROVIDED,
HOWEVER, THE FOREGOING OBLIGATION OF MLP SHALL NOT APPLY WITH RESPECT TO ANY ENVIRONMENTAL
CONDITIONS TO THE EXTENT EXISTING PRIOR TO THE CONDUCT OF SUCH DUE DILIGENCE WHICH ARE
DISCOVERED DURING SUCH DUE DILIGENCE. MLP shall comply in all material respects with all
rules, regulations, policies and instructions issued by HOLDINGS, GP or any Third Person
operator regarding MLPs actions prior to Closing while upon, entering or leaving any
property included in the Assets, including any insurance requirements that HOLDINGS may
impose on contractors authorized to perform work on any property owned or operated by
HOLDINGS.
6.4 Regulatory Filings; Hart-Scott-Rodino Filing.
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(a) MLP and HOLDINGS will take all commercially reasonable actions necessary or
desirable, and proceed diligently and in good faith and use all commercially reasonable
efforts, as promptly as practicable to obtain all consents, approvals or actions of, to make
all filings with, and to give all notices to, Governmental Authorities required to
accomplish the transactions contemplated by this Agreement; provided, however, that the cost
to obtain Post-Closing Consents shall be borne by MLP.
(b) The Parties shall make any filings required under the HSR Act on or prior to five
(5) days after the date of this Agreement and provide such information to the FTC as is
required in connection with the HSR Act as soon as practicable after a request therefore.
(c) Notwithstanding any provision herein to the contrary, each of the Parties will (i)
use reasonable efforts to comply as expeditiously as possible with all lawful requests of
Governmental Authorities for additional information and documents pursuant to the HSR Act,
(ii) not (A) extend any waiting period under the HSR Act or (B) enter into any voluntary
agreement with any Governmental Authority not to consummate the transactions contemplated by
this Agreement, except with the prior consent of the other Party, and (iii) cooperate with
each other and use reasonable efforts to obtain the requisite approval of the FTC and DOJ;
provided, however, that the Parties are not obligated to accept any conditional approval or
divest any of the Assets or any of their properties.
(d) MLP will be responsible for paying the filing fees required with respect to any
filing under the HSR Act.
6.5 Limitation on Casualty Losses and Other Matters. Notwithstanding any provision
herein to the contrary, if either HOLDINGS or MLP reasonably determines that the anticipated
aggregate value of any Casualty Losses and a good faith estimate of HOLDINGS liability with
respect to breaches of representations and warranties of which either HOLDINGS or MLP has provided
notice to the other prior to Closing, exceeds $2,500,000, then such Party shall provide written
notice to the other of such determination together with the notifying Partys calculations of the
estimated costs, payments, reductions and liabilities supporting such determination.
Notwithstanding Section 9.1(c), upon the other Partys receipt of such notice, the Party
receiving the notice shall have the right to terminate this Agreement at any time prior to Closing
upon ten (10) days written notice to the other Party.
6.6 Supplements to Exhibits and Schedules. HOLDINGS may, from time to time, by
written notice to MLP at any time prior to the Closing Date, supplement or amend the Exhibits and
Schedules to correct any matter that would constitute a breach of any representation or warranty of
HOLDINGS herein contained. MLP shall have a minimum of five (5) Business Days to review such
supplement or amendment and the Closing shall be extended as required to allow MLP to do so;
provided, however, if MLP reasonably determines that any individual new disclosure item set forth
in any such supplement or amendment would increase the amount of the Assumed Obligations by more
than $50,000, then MLP shall notify HOLDINGS of such determination together with MLPs calculations
of such increase in the amount of the Assumed Obligations. Promptly upon HOLDINGS receipt of such
written notice, the Parties shall endeavor in good faith to agree to a value to be paid by HOLDINGS
to MLP therefor or other
28
mutually agreeable remedy to address the matters which are the subject of such supplement(s)
and amendment(s) to the Exhibits and Schedules. If within fifteen (15) days of HOLDINGS receipt
of such written notice, the Parties have not agreed to a value to be paid by HOLDINGS to MLP
therefore or another mutually agreeable remedy, MLP shall have the right to terminate this
Agreement at any time during the five (5) Business Days following the expiration of such fifteen
(15) day period by provision of written notice to HOLDINGS. Notwithstanding any other provision
hereof, if the Closing occurs, any such supplement or amendment will be effective to cure and
correct for all purposes any breach of any representation or warranty that would have existed if
such supplement or amendment had not been made.
6.7 Preservation of Records. For a period of seven (7) years after the Closing Date,
the Party in possession of the originals of the Records will retain such Records at its sole cost
and expense and will make such Records available to the other Party to the extent pertaining to
such other Parties obligations hereunder upon reasonable notice for inspection and/or copying, at
the expense of the requesting Party, at the headquarters of the Party in possession (or at such
other location in the United States as the Party in possession may designate in writing to the
other Party) at reasonable times and during regular office hours. MLP agrees that HOLDINGS may
retain a copy of the Records to the extent such Records pertain to its obligations hereunder.
6.8 [Reserved]
6.9 Capital Projects.
(a) One or more of the Entities is undertaking the ongoing construction of the
natural gas gathering systems, inlet liquid handling facilities, and flare systems
described by open AFE on Schedule 6.9 (the Capital Projects). HOLDINGS
or its Affiliates shall continue to pursue the construction, on the JVs behalf, of the
Capital Projects through the Effective Time, and, from and after the Effective Time until
the third anniversary thereof, HOLDINGS will reimburse the JV on a monthly basis solely
for those costs and expenses incurred by the JV to complete the Capital Projects that are
attributable to the Subject Interests.
(b) Notwithstanding anything to the contrary set forth in this Agreement, any other
capital expenditures for projects or maintenance capital (but excluding capital
expenditures related to the Capital Projects or Casualty Losses (collectively, the
New Capital Projects) incurred between the Execution Date and Closing and
attributable to the Subject Interests shall be reimbursed by MLP to HOLDINGS as provided
in Section 2.2.
(c) Upon Closing, HOLDINGS and its Affiliates obligations for the payment or
reimbursement of costs and expenses with respect to the East Texas Inlet Liquid Handling
Facilities (as such obligations are outlined in Section 6.9 of the Prior Contribution
Agreement) shall terminate and be deemed fully satisfied, completed, and superseded, and
neither HOLDINGS nor the MLP shall have any further obligation, duty or responsibility to
make any payment or perform any duty, obligation or action under Section 6.9(c) of the
Prior Contribution Agreement from and after the Closing.
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6.10 [Reserved]
6.11 Tax Covenants; Preparation of Tax Returns. The MLP shall cause the JV to
prepare and file, or cause to be prepared and filed, all Tax Returns required to be filed by the
Entities and also shall cause the JV to cause the Entities to pay the Taxes shown to be due
thereon; provided, however, that MIDSTREAM shall promptly reimburse the MLP for the portion of such
Tax attributable to the Subject Interests that relates to a Pre-Closing Tax Period, to the extent
not accrued in the Final Settlement Statement. MIDSTREAM shall furnish to the MLP all information
and records reasonably requested by the MLP for use in preparation of any Tax Returns. The Parties
shall cause the MLP to allow MIDSTREAM to review, comment upon and reasonably approve without undue
delay any Tax Return at any time during the twenty (20) day period immediately preceding the filing
of such Tax Return.
6.12 Financial Statements and Financial Records. HOLDINGS shall consent to the
inclusion or incorporation by reference of the Annual Financial Statements in any registration
statement, report or other document of MLP or any of its Affiliates to be filed with the SEC in
which MLP or such Affiliate reasonably determines that the SEC Financial Statements are required to
be included or incorporated by reference to satisfy any rule or regulation of the SEC or to satisfy
relevant disclosure obligations under the Securities Act of 1933, as amended, or the Securities
Exchange Act of 1934, as amended. HOLDINGS shall cause its auditors to consent to the inclusion or
incorporation by reference of its audit opinion with respect to the Annual Financial Statements in
any such registration statement, report or other document and, in connection therewith, HOLDINGS
shall execute and deliver to its auditors such representation letters, in form and substance
customary for representation letters provided to external audit firms by management of the company
whose financial statements are the subject of an audit, as may be reasonably requested by its
auditors.
ARTICLE VII
CONDITIONS TO CLOSING
7.1 HOLDINGS/GPs Conditions. The obligation of HOLDINGS and GP to close is subject
to the satisfaction of the following conditions, any of which may be waived in HOLDINGS sole
discretion:
(a) The representations of MLP contained in Article V shall be true, in all
material respects (or, in the case of representations or warranties that are already
qualified by a materiality standard, shall be true in all respects) on and as of Closing.
(b) MLP shall have performed in all material respects the obligations, covenants and
agreements of MLP contained herein.
(c) There is no injunction, restraining order or Proceeding pending against HOLDINGS or
the Entities that restrains or prohibits the consummation of the transactions contemplated
by this Agreement.
(d) All of HOLDINGS Required Consents, MLPs Required Consents, consents under the
Real Property Interests, Contracts and Permits and consents or
30
approvals under the HSR Act (or expiration of the waiting period) shall have been
obtained.
(e) MLP shall have made all deliveries in accordance with Section 8.2(b).
7.2 MLPs Conditions. The obligation of MLP to close is subject to the satisfaction
of the following conditions, any of which may be waived in its sole discretion:
(a) The representations of HOLDINGS contained in Article IV shall be true, in
all material respects (or in the case of representations or warranties that are already
qualified by a materiality standard, shall be true in all respects) on and as of the
Closing.
(b) HOLDINGS shall have performed, in all material respects, the obligations, covenants
and agreements of HOLDINGS contained herein.
(c) There is no injunction, restraining order or Proceeding pending against HOLDINGS or
the Entities that restrains or prohibits the consummation of the transactions contemplated
by this Agreement.
(d) All of HOLDINGS Required Consents, MLPs Required Consents, consents under the
Real Property Interests, Contracts and Permits and consents or approvals under the HSR Act
(or expiration of the waiting period) shall have been obtained.
(e) There shall have been no events or occurrences that could reasonably be expected to
have a Material Adverse Effect.
(f) HOLDINGS shall have delivered all documents in accordance with Section
8.2(a).
(g) MLP shall have received audited financial statements for the JV for the year ended
December 31, 2008, that are satisfactory to MLP in its sole discretion.
7.3 Exceptions. Notwithstanding the provisions of Sections 7.1(a) and
(b) and 7.2(a) and (b), no Party shall have the right to refuse to close
the transaction contemplated hereby by reason of this Article VII unless (a) in the case of
HOLDINGS and GP , the sum of all representations of MLP contained in Article V which are
not true and all obligations, covenants and agreements which MLP has failed to perform, would
reasonably be expected to have a Material Adverse Effect, and (b) in the case of MLP, the sum of
all representations of HOLDINGS and GP contained in Article IV which are not true and all
obligations, covenants and agreements which HOLDINGS and GP has failed to perform, would reasonably
be expected to have a Material Adverse Effect.
ARTICLE VIII
CLOSING
8.1 Time and Place of Closing. The consummation of the transactions contemplated by
this Agreement (the Closing) shall take place in the offices of MIDSTREAM in Denver,
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Colorado at (a) a pre-closing at 9:00 a.m. on March 31, 2009 (at which the Transaction
Documents and Officers Certificates will be executed) and (b) a final closing at 9:00 a.m. Denver
time on April 1, 2009 (unless such date is otherwise extended by either HOLDINGS or MLP as
permitted hereunder); or on the last day of the month following the receipt of the consents
required by Sections 7.1(d) and 7.2(d) (if later than the foregoing specified date
of Closing), or such other time and place as the Parties agree to in writing (the Closing
Date), and shall be effective as of the Effective Time.
8.2 Deliveries at Closing. At the Closing,
(a) HOLDINGS and GP, as applicable, will execute and deliver or cause to be executed
and delivered to MLP:
(i) Each of the Transaction Documents to which HOLDINGS, GP or Affiliates are a
party;
(ii) Certificates of a corporate officer or other authorized person dated the
Closing Date, certifying on behalf of HOLDINGS and GP that the conditions in
Sections 7.2(a) and (b) have been fulfilled.
(b) MLP will execute and deliver or cause to be executed and delivered to HOLDINGS and
GP:
(i) Each of the Transaction Documents to which MLP or MLPs Affiliates are a
party;
(ii) A certificate of a corporate officer or other authorized person dated the
Closing Date certifying on behalf of MLP that the conditions in Sections
7.1(a) and (b) have been fulfilled;
(iii) Certificates for Class D Units, determined in accordance with
Sections 2.2 and 2.3;
(iv) A wire transfer to HOLDINGS and GP of the amounts due with respect to the
Total Net Working Capital and New Capital Projects (as set forth in the Preliminary
Settlement Statement).
ARTICLE IX
TERMINATION
9.1 Termination. This Agreement may be terminated and the transactions contemplated
hereby abandoned as follows:
(a) HOLDINGS and MLP may elect to terminate this Agreement at any time prior to the
Closing by mutual written consent thereof;
(b) Either HOLDINGS or MLP by written notice to the other may terminate this Agreement
if the Closing shall not have occurred on or before June 1, 2009;
32
provided, however, that neither Party may terminate this Agreement if such Party is at
such time in material breach of any provision of this Agreement;
(c) HOLDINGS and MLP may each terminate this Agreement at any time on or prior to the
Closing if either MLP, on the one hand, or HOLDINGS, on the other hand, shall have
materially breached any representations, warranties or covenants thereof herein contained
with the sum of such breach or breaches reasonably expected to have a Material Adverse
Effect and the same is not cured within thirty (30) days after receipt of written notice
thereof from the applicable non-breaching Party; provided, however, that neither Party may
terminate this Agreement if such Party is at such time in material breach of any
representations, warranties or covenants of such Party; and
(d) In addition to the foregoing, any Party may terminate this Agreement to the extent
such termination is expressly authorized by another provision of this Agreement.
9.2 Effect of Termination Prior to Closing. If Closing does not occur as a result of
any Party exercising its right to terminate pursuant to Section 9.1, then no Party shall
have any further rights or obligations under this Agreement, except that (i) nothing herein shall
relieve any Party from any liability for any willful breach of this Agreement, and (ii) the
provisions of Section 6.3(c) and Article XI shall survive any termination of this
Agreement.
ARTICLE X
INDEMNIFICATION
10.1 Indemnification by MLP. Effective upon Closing, MLP shall defend, indemnify and
hold harmless HOLDINGS and its Affiliates, and all of its and their directors, officers, employees,
partners, members, contractors, agents, and representatives (collectively, the HOLDINGS
Indemnitees) from and against any and all Losses asserted against, resulting from, imposed
upon or incurred by any of the HOLDINGS Indemnitees as a result of or arising out of:
(a) the breach of any of the representations or warranties under Article V;
(b) the breach of any covenants or agreements of MLP contained in this Agreement; and
(c) to the extent that HOLDINGS is not required to indemnify any of the MLP Indemnitees
pursuant to Section 10.2, the Assumed Obligations.
10.2 Indemnification by HOLDINGS. Effective upon Closing, HOLDINGS shall defend,
indemnify and hold harmless MLP and its Affiliates, and all of its and their directors, officers,
employees, partners, members, contractors, agents, and representatives (collectively, the MLP
Indemnitees) from and against any and all Losses asserted against, resulting from, imposed
upon or incurred by any of the MLP Indemnitees as a result of or arising out of:
(a) the breach of any of the representations or warranties under Article IV
(other than Sections 4.1, 4.2, 4.16 and 4.17),
33
(b) subject to Section 6.9, to the extent not accounted for in the Final
Settlement Statement, Claims asserted within one (1) year after Closing to the extent
related to underpayment of trade payables for periods prior to the Effective Time;
(c) with respect to the Former UP Fuels Properties, Claims by Governmental Authorities
asserted within two (2) years after Closing to the extent related to fines and penalties for
periods between April 1, 1999 and Closing;
(d) with respect to the Former Gulf South Properties, Claims by Governmental
Authorities asserted within two (2) years after Closing to the extent related to fines and
penalties for periods between March 31, 2005 and Closing;
(e) to the extent and subject to any limitations provided therein, any matters set
forth on Schedule 10.2(e);
(f) the breach of any of the representations or warranties under Sections 4.1,
4.2, 4.16 and 4.17 or the covenants or agreements of HOLDINGS
contained in this Agreement; and
(g) any Reserved Liabilities.
10.3 Deductibles, Caps, Survival and Certain Limitations.
(a) Subject to this Section 10.3, all representations, warranties, covenants
and indemnities made by the Parties in this Agreement or pursuant hereto shall survive the
Closing as hereinafter provided, and shall not be merged into any instruments or agreements
delivered at Closing.
(b) With respect to the obligations of HOLDINGS:
(i) under Sections 10.2(a) or (b), none of the MLP Indemnitees
shall be entitled to assert any right to indemnification after one (1) year from the
Closing;
(ii) under Section 10.2(c) or (d), none of the MLP Indemnitees
shall be entitled to assert any right to indemnification after two (2) years from
the Closing;
(iii) under Section 10.2(a), none of the MLP Indemnitees shall be
entitled to assert any right to indemnification unless the individual claim or
series of related claims which arise out of substantially the same facts and
circumstances exceeds $50,000 (Qualified Claims);
(iv) under Section 10.2(a), none of the MLP Indemnitees shall be
entitled to assert any right to indemnification unless Qualified Claims for which
indemnity is only provided under Section 10.2(a) shall in the aggregate
exceed $450,000 and then only to the extent that all such Qualified Claims exceed
said amount;
34
(v) under Section 10.2(a), none of the MLP Indemnitees shall be
entitled to indemnification for any amount in excess of $4,500,000; and
(vi) Any indemnification or payment obligations of HOLDINGS under
Section 10.2 resulting from HOLDINGS breach of its representations,
warranties, covenants or agreements, shall be limited to Losses that are
attributable to the Subject Interests or to the transactions pursuant to which MLP
acquires the Subject Interests under this Agreement, and MLP shall have no right to
assert any claim under this Agreement related to the 25% member interest in the JV
that was acquired under the Prior Contribution Agreement. Notwithstanding the
foregoing, the indemnification rights of MLP and any MLP Indemnitee under the Prior
Contribution Agreement shall not be terminated or impaired by any provision this
Agreement, including, without limitation, MLPs or any MLP Indemnitees right to be
indemnified for HOLDINGS breach of any representation, warranty, covenant or
agreement under the Prior Contribution Agreement.
(c) Any claim for indemnity under this Agreement made by a Party Indemnitee shall be in
writing, be delivered in good faith prior to the expiration of the respective survival
period under Section 10.3(b) (to the extent applicable), and specify in reasonable
detail the specific nature of the claim for indemnification hereunder (Claim
Notice). Any such claim that is described in a timely (if applicable) delivered Claim
Notice shall survive with respect to the specific matter described therein.
(d) Notwithstanding anything contained herein to the contrary, in no event shall
HOLDINGS be obligated under this Agreement to indemnify (or be otherwise liable hereunder in
any way whatsoever to) any of the MLP Indemnitees with respect to a breach of any
representation or warranty, if MLP had Knowledge thereof at Closing and failed to notify
HOLDINGS of such breach prior to Closing. Unless HOLDINGS or a Third Person shall have made
a claim or demand or it appears reasonably likely that such a claim or demand appears
reasonably likely, MLP shall not take any voluntary action that is intended by MLP to cause
a Claim to be initiated that would be subject to indemnification by HOLDINGS.
(e) All Losses indemnified hereunder shall be determined net of any (i) Third Person
Awards, (ii) Tax Benefits; and (iii) amount which specifically pertains to such Loss and is
reflected in the calculations of the amounts set forth on the Final Settlement Statement.
10.4 Notice of Asserted Liability; Opportunity to Defend.
(a) All claims for indemnification hereunder shall be subject to the provisions of this
Section 10.4. Any person claiming indemnification hereunder is referred to herein
as the Indemnified Party or Indemnitee and any person against whom such claims are
asserted hereunder is referred to herein as the Indemnifying Party or Indemnitor.
35
(b) If any Claim is asserted against or any Loss is sought to be collected from an
Indemnified Party, the Indemnified Party shall with reasonable promptness provide to the
Indemnifying Party a Claim Notice. The failure to give any such Claim Notice shall not
otherwise affect the rights of the Indemnified Party to indemnification hereunder unless the
Indemnified Party has proceeded to contest, defend or settle such Claim or remedy such a
Loss with respect to which it has failed to give a Claim Notice to the Indemnifying Party,
but only to the extent the Indemnifying Party is prejudiced thereby. Additionally, to the
extent the Indemnifying Party is prejudiced thereby, the failure to provide a Claim Notice
to the Indemnifying Party shall relieve the Indemnifying Party from liability for such
Claims and Losses that it may have to the Indemnified Party, but only to the extent the
liability for such Claims or Losses is directly attributable to such failure to provide the
Claim Notice.
(c) The Indemnifying Party shall have thirty (30) days from the personal delivery or
receipt of the Claim Notice (the Notice Period) to notify the Indemnified Party
(i) whether or not it disputes the liability to the Indemnified Party hereunder with respect
to the Claim or Loss, and in the event of a dispute, such dispute shall be resolved in the
manner set forth in Section 11.8 hereof, (ii) in the case where Losses are asserted
against or sought to be collected from an Indemnifying Party by the Indemnified Party,
whether or not the Indemnifying Party shall at its own sole cost and expense remedy such
Losses or (iii) in the case where Claims are asserted against or sought to be collected from
an Indemnified Party, whether or not the Indemnifying Party shall at its own sole cost and
expense defend the Indemnified Party against such Claim; provided however, that any
Indemnified Party is hereby authorized prior to and during the Notice Period to file any
motion, answer or other pleading that it shall deem necessary or appropriate to protect its
interests or those of the Indemnifying Party (and of which it shall have given notice and
opportunity to comment to the Indemnifying Party) and not prejudicial to the Indemnifying
Party.
(d) If the Indemnifying Party does not give notice to the Indemnified Party of its
election to contest and defend any such Claim described in Section 10.4(c)(iii)
within the Notice Period, then the Indemnifying Party shall be bound by the result obtained
with respect thereto by the Indemnified Party and shall be responsible for all costs
incurred in connection therewith.
(e) If the Indemnifying Party is obligated to defend and indemnify the Indemnified
Party, and the Parties have a conflict of interest with respect to any such Claim, then the
Indemnified Party may, in its sole discretion, separately and independently contest and
defend such Claim, and the Indemnifying Party shall be bound by the result obtained with
respect thereto by the Indemnified Party and shall be responsible for all costs incurred in
connection therewith.
(f) If the Indemnifying Party notifies the Indemnified Party within the Notice Period
that it shall defend the Indemnified Party against a Claim, the Indemnifying Party shall
have the right to defend all appropriate Proceedings, and with counsel of its own choosing
(but reasonably satisfactory to the Indemnified Party) and such Proceedings shall be
promptly settled (subject to obtaining a full and complete release of all
36
Indemnified Parties) or prosecuted by it to a final conclusion. If the Indemnified
Party desires to participate in, but not control, any such defense or settlement it may do
so at its sole cost and expense. If the Indemnified Party joins in any such Claim, the
Indemnifying Party shall have full authority to determine all action to be taken with
respect thereto, as long as such action could not create a liability to any of the
Indemnified Parties, in which case, such action would require the prior written consent of
any Indemnified Party so affected.
(g) If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate
with the Indemnifying Party and its counsel in contesting any Claim and in making any
counterclaim against the Third Person asserting the Claim, or any cross-complaint against
any person as long as such cooperation, counterclaim or cross-complaint could not create a
liability to any of the Indemnified Parties.
(h) At any time after the commencement of defense by Indemnifying Party under
Section 10.4(f) above of any Claim, the Indemnifying Party may request the
Indemnified Party to agree in writing to the abandonment of such contest or to the payment
or compromise by the Indemnifying Party of the asserted Claim, but only if the Indemnifying
Party agrees in writing to be solely liable for such Claim; whereupon such action shall be
taken unless the Indemnified Party determines that the contest should be continued and
notifies the Indemnifying Party in writing within fifteen (15) days of such request from the
Indemnifying Party. If the Indemnified Party determines that the contest should be
continued, the amount for which the Indemnifying Party would otherwise be liable hereunder
shall not exceed the amount which the Indemnifying Party had agreed to pay to compromise
such Claim; provided that, the other Person to the contested Claim had agreed in writing to
accept such amount in payment or compromise of the Claim as of the time the Indemnifying
Party made its request therefor to the Indemnified Party, and further provided that, under
such proposed compromise, the Indemnified Party would be fully and completely released from
any further liability or obligation with respect to the matters which are the subject of
such contested Claim.
10.5 Materiality Conditions. For purposes of determining whether an event described
in this Article X has occurred for which indemnification under this Article X can
be sought, any requirement in any representation, warranty, covenant or agreement by HOLDINGS or
MLP, as applicable, contained in this Agreement that an event or fact be material, Material,
meet a certain minimum dollar threshold or have a Material Adverse Effect or a material adverse
effect (each a Materiality Condition) in order for such event or fact to constitute a
misrepresentation or breach of such representation, warranty, covenant or agreement under this
Agreement, such Materiality Condition shall be disregarded and such representations, warranties,
covenants or agreements shall be construed solely for purposes of this Article X as if they
did not contain such Materiality Conditions. Notwithstanding anything in this Section
10.5, any claim for indemnification under this Article X will be subject to Section
10.3.
10.6 Exclusive Remedy. AS BETWEEN THE MLP INDEMNITEES AND THE HOLDINGS INDEMNITEES,
AFTER CLOSING (A) THE EXPRESS INDEMNIFICATION PROVISIONS SET FORTH IN THIS AGREEMENT, WILL BE THE
SOLE AND EXCLUSIVE RIGHTS, OBLIGATIONS AND REMEDIES OF THE PARTIES WITH
37
RESPECT TO SAID AGREEMENT AND THE EVENTS GIVING RISE THERETO, AND THE TRANSACTIONS PROVIDED
FOR THEREIN OR CONTEMPLATED THEREBY (OTHER THAN THE OTHER TRANSACTION DOCUMENTS) AND (B) NO PARTY
HERETO NOR ANY OF ITS RESPECTIVE SUCCESSORS OR ASSIGNS SHALL HAVE ANY RIGHTS AGAINST ANY OTHER
PARTY OR ITS AFFILIATES WITH RESPECT TO THE TRANSACTIONS PROVIDED FOR HEREIN OTHER THAN AS IS
EXPRESSLY PROVIDED IN THIS AGREEMENT AND THE OTHER TRANSACTION DOCUMENTS.
10.7 Negligence and Strict Liability Waiver. WITHOUT LIMITING OR ENLARGING THE SCOPE
OF THE INDEMNIFICATION OBLIGATIONS SET FORTH IN THIS AGREEMENT, AN INDEMNIFIED PARTY SHALL BE
ENTITLED TO INDEMNIFICATION UNDER THIS AGREEMENT IN ACCORDANCE WITH THE TERMS HEREOF, REGARDLESS OF
WHETHER THE LOSS OR CLAIM GIVING RISE TO SUCH INDEMNIFICATION OBLIGATION IS THE RESULT OF THE SOLE,
CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY, OR VIOLATION OF ANY LAW OF OR BY SUCH
INDEMNIFIED PARTY.
10.8 Limitation on Damages. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS
AGREEMENT, IN NO EVENT SHALL ANY OF HOLDINGS, GP OR MLP BE LIABLE TO THE OTHER, OR TO THE OTHERS
INDEMNITEES, UNDER THIS AGREEMENT FOR ANY EXEMPLARY, PUNITIVE, REMOTE, SPECULATIVE, CONSEQUENTIAL,
SPECIAL OR INCIDENTAL DAMAGES OR LOSS OF PROFITS; PROVIDED THAT, IF ANY OF THE HOLDINGS INDEMNITEES
OR MLP INDEMNITEES IS HELD LIABLE TO A THIRD PERSON FOR ANY SUCH DAMAGES AND THE INDEMNITOR IS
OBLIGATED TO INDEMNIFY SUCH HOLDINGS INDEMNITEES OR MLP INDEMNITEES FOR THE MATTER THAT GAVE RISE
TO SUCH DAMAGES, THE INDEMNITOR SHALL BE LIABLE FOR, AND OBLIGATED TO REIMBURSE SUCH INDEMNITEES
FOR SUCH DAMAGES.
10.9 Bold and/or Capitalized Letters. THE PARTIES AGREE THAT THE BOLD AND/OR
CAPITALIZED LETTERS IN THIS AGREEMENT CONSTITUTE CONSPICUOUS LEGENDS.
ARTICLE XI
MISCELLANEOUS PROVISIONS
11.1 Expenses. Unless otherwise specifically provided for herein, each Party will
bear its own costs and expenses (including legal fees and expenses) incurred in connection with the
negotiation of this Agreement and the transactions contemplated hereby; provided that HOLDINGS will
bear the cost of all Post-Closing Consents which must be obtained from any railroad.
11.2 Further Assurances. From time to time, and without further consideration, each
Party will execute and deliver to the other Party such documents and take such actions as the other
Party may reasonably request in order to more effectively implement and carry into effect the
transactions contemplated by this Agreement.
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11.3 Transfer Taxes. The Parties believe that the contribution of the Subject
Interests as provided for herein is exempt from or is otherwise not subject to any and all sales,
use, transfer, or similar Taxes. If any such sales, transfer, use or similar Taxes are due or
should hereafter become due (including penalty and interest thereon) by reason of this transaction,
MLP shall timely pay and solely bear all such type of Taxes.
11.4 Assignment. Neither Party may assign this Agreement or any of its rights or
obligations arising hereunder without the prior written consent of the other Party; provided,
however, MLP shall be permitted to assign this Agreement to an Affiliate prior to Closing,
provided, that, notwithstanding such assignment, MLP shall continue to remain responsible for all
obligations of MLP hereunder following such assignment.
11.5 Entire Agreement, No Amendment of Prior Transaction Agreement, Amendments and
Waiver. This Agreement, together with the Transaction Documents and all certificates,
documents, instruments and writings that are delivered pursuant hereto and thereto contain the
entire understanding of the Parties with respect to the transactions contemplated hereby and
supersede all prior agreements, arrangements and understandings relating to the subject matter
hereof. Except as specified in Section 6.9, no term, provision or aspect of this Agreement
or of any other Transaction Document shall have the effect of terminating, amending, extending, or
enlarging or limiting the scope or intent, or of in any manner superseding the Prior Contribution
Agreement or the transactions documents executed in connection therewith. This Agreement may be
amended, superseded or canceled only by a written instrument duly executed by the Parties
specifically stating that it amends, supersedes or cancels this Agreement. Any of the terms of
this Agreement and any condition to a Partys obligations hereunder may be waived only in writing
by that Party specifically stating that it waives a term or condition hereof. No waiver by either
Party of any one or more conditions or defaults by the other in performance of any of the
provisions of this Agreement shall operate or be construed as a waiver of any future conditions or
defaults, whether of a like or different character, nor shall the waiver constitute a continuing
waiver unless otherwise expressly provided.
11.6 Severability. Each portion of this Agreement is intended to be severable. If
any term or provision hereof is illegal or invalid for any reason whatsoever, such illegality or
invalidity shall not affect the validity of the remainder of this Agreement.
11.7 Counterparts. This Agreement may be executed simultaneously in any number of
counterparts, each of which shall be deemed an original, but all of which together shall constitute
one and the same instrument.
11.8 Governing Law, Dispute Resolution and Arbitration.
(a) Governing Law. This Agreement shall be governed by, enforced in accordance
with, and interpreted under, the Laws of the State of Colorado, without reference to
conflicts of Laws principles.
(b) Negotiation. In the event of any Arbitral Dispute, the Parties shall
promptly seek to resolve any such Arbitral Dispute by negotiations between senior executives
of the Parties who have authority to settle the Arbitral Dispute. When a Party
39
believes there is an Arbitral Dispute under this Agreement that Party will give the
other Party written notice of the Arbitral Dispute. Within thirty (30) days after receipt
of such notice, the receiving Party shall submit to the other a written response. Both the
notice and response shall include (i) a statement of each Partys position and a summary of
the evidence and arguments supporting such position, and (ii) the name, title, fax number,
and telephone number of the executive or executives who will represent that Party. If the
Arbitral Dispute involves a claim arising out of the actions of any Person not a signatory
to this Agreement, the receiving Party shall have such additional time as necessary, not to
exceed an additional thirty (30) days, to investigate the Arbitral Dispute before submitting
a written response. The executives shall meet at a mutually acceptable time and place
within fifteen (15) days after the date of the response and thereafter as often as they
reasonably deem necessary to exchange relevant information and to attempt to resolve the
Arbitral Dispute. If one of the executives intends to be accompanied at a meeting by an
attorney, the other executive shall be given at least five (5) Business Days notice of such
intention and may also be accompanied by an attorney.
(c) Failure to Resolve. If the Arbitral Dispute has not been resolved within
sixty (60) days after the date of the response given pursuant to Section 11.8(b)
above, or such additional time, if any, that the Parties mutually agree to in writing, or if
the Party receiving such notice denies the applicability of the provisions of Section
11.8(b) or otherwise refuses to participate under the provisions of Section
11.8(b), either Party may initiate binding arbitration pursuant to the provisions of
Section 11.8(d) below.
(d) Arbitration. Any Arbitral Disputes not settled pursuant to the foregoing
provisions shall be resolved through the use of binding arbitration in accordance with the
Commercial Arbitration Rules of the American Arbitration Association (Arbitration
Rules), as supplemented to the extent necessary to determine any procedural appeal
questions by the Federal Arbitration Act (Title 9 of the United States Code) and in
accordance with the following provisions:
(i) If there is any inconsistency between this Section 11.8(d) and the
Arbitration Rules or the Federal Arbitration Act, the terms of this Section
11.8(d) will control the rights and obligations of the Parties.
(ii) Arbitration shall be initiated by a Party serving written notice, via
certified mail, on the other Party that the first Party elects to refer the Arbitral
Dispute to binding arbitration, along with the name of the arbitrator appointed by
the Party demanding arbitration and a statement of the matter in controversy.
Within thirty (30) days after receipt of such demand for arbitration, the receiving
Party shall name its arbitrator. If the receiving Party fails or refuses to name
its arbitrator within such thirty (30) day period, the second arbitrator shall be
appointed, upon request of the Party demanding arbitration, by the Chief U.S.
District Court Judge for the District of Colorado, or such other person designated
by such judge. The two arbitrators so selected shall within thirty (30) days after
their designation select a third arbitrator; provided, however, that if the two
arbitrators are not able to agree on a third arbitrator within such thirty (30) day
period, either Party may request the Chief U.S. District Court Judge for the
40
District of Colorado, or such other person designated by such judge to select
the third arbitrator as soon as possible. If the Judge declines to appoint an
arbitrator, appointment shall be made, upon application of either Party, pursuant to
the Commercial Arbitration Rules of the American Arbitration Association. If any
arbitrator refuses or fails to fulfill his or her duties hereunder, such arbitrator
shall be replaced by the Party which selected such arbitrator (or if such arbitrator
was selected by another Person, through the procedure which such arbitrator was
selected) pursuant to the foregoing provisions.
(iii) The hearing will be conducted in Denver, Colorado, no later than sixty
(60) days following the selection of the arbitrators or thirty (30) days after all
prehearing discovery has been completed, whichever is later, at which the Parties
shall present such evidence and witnesses as they may choose, with or without
counsel. The Parties and the arbitrators should proceed diligently and in good
faith in order that the award may be made as promptly as possible.
(iv) Except as provided in the Federal Arbitration Act, the decision of the
arbitrators will be binding on and non-appealable by the Parties. Any such decision
may be filed in any court of competent jurisdiction and may be enforced by any Party
as a final judgment in such court.
(v) The arbitrators shall have no right or authority to grant or award
exemplary, punitive, remote, speculative, consequential, special or incidental
damages.
(vi) The Federal Rules of Civil Procedure, as modified or supplemented by the
local rules of civil procedure for the U.S. District Court of Colorado, shall apply
in the arbitration. The Parties shall make their witnesses available in a timely
manner for discovery pursuant to such rules. If a Party fails to comply with this
discovery agreement within the time established by the arbitrators, after resolving
any discovery disputes, the arbitrators may take such failure to comply into
consideration in reaching their decision. All discovery disputes shall be resolved
by the arbitrators pursuant to the procedures set forth in the Federal Rules of
Civil Procedure.
(vii) Adherence to formal rules of evidence shall not be required. The
arbitrators shall consider any evidence and testimony that they determine to be
relevant.
(viii) The Parties hereby request that the arbitrators render their decision
within thirty (30) days following conclusion of the hearing.
(ix) The defenses of statute of limitations and laches shall be tolled from and
after the date a Party gives the other Party written notice of an Arbitral Dispute
as provided in Section 11.8(b) above until such time as the Arbitral Dispute
has been resolved pursuant to Section 11.8(b), or an arbitration award has
been entered pursuant to this Section 11.8(d).
41
(e) Recovery of Costs and Attorneys Fees. If arbitration arising out of this
Agreement is initiated by either Party, the decision of the arbitrators may include the
award of court costs, fees and expenses of such arbitration (including reasonable attorneys
fees).
(f) Choice of Forum. If, despite the Parties agreement to submit any Arbitral
Disputes to binding arbitration, there are any court proceedings arising out of or relating
to this Agreement or the transactions contemplated hereby, such proceedings shall be brought
and tried in, and the Parties hereby consent to the jurisdiction of, the federal or state
courts situated in the City and County of Denver, State of Colorado.
(g) Jury Waivers. THE PARTIES HEREBY WAIVE ANY AND ALL RIGHTS TO DEMAND A
TRIAL BY JURY.
(h) Settlement Proceedings. All aspects of any settlement proceedings,
including discovery, testimony and other evidence, negotiations and communications pursuant
to this Section 11.8, briefs and the award shall be held confidential by each Party
and the arbitrators, and shall be treated as compromise and settlement negotiations for the
purposes of the Federal and State Rules of Evidence.
11.9 Notices and Addresses. Any notice, request, instruction, waiver or other
communication to be given hereunder by either Party shall be in writing and shall be considered
duly delivered if personally delivered, mailed by certified mail with the postage prepaid (return
receipt requested), sent by messenger or overnight delivery service, or sent by facsimile to the
addresses of the Parties as follows:
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MLP:
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DCP Midstream Partners, LP |
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370 17th Street, Suite 2775 |
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Denver, Colorado 80202 |
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Telephone: (303) 633-2900 |
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Facsimile: (303) 633-2921 |
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Attn: President |
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with a copy to:
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DCP Midstream Partners, LP |
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370 17th Street, Suite 2775 |
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Denver, Colorado 80202 |
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Telephone: (303) 633-2900 |
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Facsimile: (303) 633-2921 |
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Attn: General Counsel |
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MIDSTREAM, GP or HOLDINGS:
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DCP Midstream, LLC |
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370 17th Street, Suite 2500 |
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Denver, Colorado 80202 |
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Telephone: (303) 595-3331 |
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Facsimile: (303) 605-2226 |
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Attn: President |
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with a copy to:
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DCP Midstream, LLC |
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370 17th Street, Suite 2500 |
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Denver, Colorado 80202 |
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Telephone: (303) 605-1630 |
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Facsimile: (303) 605-2226 |
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Attn: General Counsel |
or at such other address as either Party may designate by written notice to the other Party in the
manner provided in this Section 11.9. Notice by mail shall be deemed to have been given
and received on the third (3rd) day after posting. Notice by messenger, overnight delivery
service, facsimile transmission (with answer-back confirmation) or personal delivery shall be
deemed given on the date of actual delivery.
11.10 Press Releases. Except as may otherwise be required by securities Laws and
public announcements or disclosures that are, in the reasonable opinion of the Party proposing to
make the announcement or disclosure, legally required to be made, there shall be no press release
or public communication concerning the transactions contemplated by this Agreement by either Party
except with the prior written consent of the Party not originating such press release or
communication, which consent shall not be unreasonably withheld or delayed. MLP, GP and HOLDINGS
will consult in advance on the necessity for, and the timing and content of, any communications to
be made to the public and, subject to legal constraints, to the form and content of any application
or report to be made to any Governmental Authority that relates to the transactions contemplated by
this Agreement.
11.11 Offset. Nothing contained herein or in any Transaction Document shall create a
right of offset or setoff for any Party under this Agreement and each Party hereby waives and
disclaims any such right of offset or setoff under all applicable Law (including common Law).
11.12 No Partnership; Third Party Beneficiaries. Nothing in this Agreement shall be
deemed to create a joint venture, partnership, tax partnership, or agency relationship between the
Parties. Nothing in this Agreement shall provide any benefit to any Third Person or entitle any
Third Person to any claim, cause of action, remedy or right of any kind, it being the intent of the
Parties that this Agreement shall not be construed as a third-party beneficiary contract; provided,
however, that the indemnification provisions of Article X shall inure to the benefit of the
MLP Indemnitees and the HOLDINGS Indemnitees as provided therein.
11.13 Negotiated Transaction. The provisions of this Agreement were negotiated by the
Parties, and this Agreement shall be deemed to have been drafted by both Parties.
THE PARTIES HAVE signed this Agreement by their duly authorized officials as of the date first
set forth above.
[Signatures begin on next page]
43
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DCP LP HOLDINGS, LLC |
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By:
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/s/ D. Robert Sadler |
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Name:
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D. Robert Sadler |
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Title:
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Vice President, Strategic Planning |
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DCP MIDSTREAM, LLC |
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By:
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/s/ D. Robert Sadler |
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Name:
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D. Robert Sadler |
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Title:
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Vice President, Strategic Planning |
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DCP MIDSTREAM GP, LP |
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By: DCP MIDSTREAM GP, LLC,
Its General Partner |
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By:
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/s/ Donald A. Baldridge |
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Name:
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Donald A. Baldridge |
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Title:
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Vice President, Business Development |
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DCP MIDSTREAM PARTNERS, LP |
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By: DCP MIDSTREAM GP, LP, |
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Its General Partner |
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By: DCP MIDSTREAM GP, LLC, |
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Its General Partner |
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By:
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/s/ Donald A. Baldridge |
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Name:
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Donald A. Baldridge |
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Title:
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Vice President, Business Development |
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Signature page to Contribution Agreement
exv12w1
Exhibit 12.1
RATIO OF EARNINGS TO FIXED CHARGES
The table below sets forth the calculation of Ratios of Earnings to Fixed Charges.
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DCP Midstream Partners, LP |
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Year Ended December 31, |
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2008 |
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2007 |
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2006 |
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2005 |
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2004 |
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(Millions) |
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Earnings from continuing operations before fixed charges |
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Pretax income (loss) from continuing operations before
income or loss from equity method investments |
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$ |
91.5 |
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$ |
(55.0 |
) |
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$ |
32.7 |
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$ |
47.4 |
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$ |
30.2 |
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Fixed charges |
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33.6 |
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27.0 |
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12.6 |
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1.5 |
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0.1 |
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Amortization of capitalized interest |
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0.1 |
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Distributed income of equity method investments |
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34.3 |
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38.9 |
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25.9 |
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25.7 |
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13.4 |
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Less: |
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Capitalized interest |
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(0.3 |
) |
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(0.2 |
) |
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(0.4 |
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Earnings from continuing operations before fixed charges |
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$ |
159.2 |
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$ |
10.7 |
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$ |
70.8 |
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$ |
74.6 |
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$ |
43.7 |
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Fixed charges |
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Interest expense, net of capitalized interest |
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$ |
32.6 |
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$ |
26.0 |
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$ |
11.4 |
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$ |
0.8 |
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$ |
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Capitalized interest |
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0.3 |
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0.2 |
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0.4 |
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Estimate of interest within rental expense |
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0.5 |
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0.6 |
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0.7 |
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0.7 |
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0.1 |
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Amortization of deferred loan costs |
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0.2 |
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0.2 |
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0.1 |
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Total fixed charges |
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$ |
33.6 |
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$ |
27.0 |
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$ |
12.6 |
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$ |
1.5 |
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$ |
0.1 |
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Ratio of earnings to fixed charges |
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4.74 |
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0.40 |
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5.62 |
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49.73 |
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437.0 |
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For purposes of determining the ratio of earnings to fixed charges, earnings are defined as
pretax income or loss from continuing operations before income or loss from equity method
investments, plus fixed charges, plus distributed income of equity method investments, less
capitalized interest. Fixed charges consist of interest expensed, capitalized interest,
amortization of deferred loan costs, and an estimate of the interest within rental expense.
exv21w1
Exhibit 21.1
SUBSIDIARIES OF DCP MIDSTREAM PARTNERS, LP
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Entity |
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Jurisdiction of Organization |
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Associated Louisiana Intrastate Pipe Line, LLC |
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Delaware |
Collbran Valley Gas Gathering, LLC |
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Colorado |
DCP Antrim Gas, LLC |
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Michigan |
DCP Assets Holding GP, LLC |
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Delaware |
DCP Assets Holding, LP |
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Delaware |
DCP Bay Area Pipeline, LLC |
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Michigan |
DCP Black Lake Holding, LP |
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Delaware |
DCP Collbran, LLC |
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Colorado |
DCP Douglas, LLC |
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Colorado |
DCP Grand Lacs, LLC |
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Michigan |
DCP Intrastate Pipeline, LLC |
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Delaware |
DCP Jackson, LLC |
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Michigan |
DCP Lindsay, LLC |
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Delaware |
DCP Litchfield, LLC |
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Michigan |
DCP Michigan Pipeline & Processing, LLC |
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Michigan |
DCP Midstream Partners Finance Corp. |
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Delaware |
DCP Midstream Operating, LLC |
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Delaware |
DCP Midstream Operating, LP |
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Delaware |
Gas Supply Resources LLC |
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Texas |
GSRI Transportation LLC |
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Texas |
Jackson Pipeline Company |
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Michigan |
Pelico Pipeline, LLC |
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Delaware |
Wilbreeze Pipeline, LLC |
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Delaware |
exv23w1
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8
and in Amendment No. 1 to Registration Statements No. 333-142278 and No. 333-146832 on Form S-3 of
our reports dated March 4, 2009, relating to (1) the consolidated financial statements and
financial statement schedule of DCP Midstream Partners, LP (which report expresses an unqualified
opinion and includes explanatory paragraphs referring to the preparation of the portion of the DCP
Midstream Partners, LP consolidated financial statements attributable to (a) the wholesale propane
logistics business and (b) DCP East Texas Holdings, LLC, Discovery Producer Services, LLC, and a
non-trading derivative instrument from the separate records maintained by DCP Midstream, LLC) and
(2) the effectiveness of DCP Midstream Partners, LPs internal control over financial reporting,
appearing in this Annual Report on Form 10-K of DCP Midstream Partners, LP for the year ended
December 31, 2008.
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/s/ Deloitte & Touche LLP
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Denver, Colorado March 4, 2009 |
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exv23w2
Exhibit 23.2
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statements on Form S-8 (No.
333-142271) and Form S-3 (No. 333-142278 and 333-146832) of DCP Midstream Partners, LP of our
report dated February 23, 2009, with respect to the consolidated financial statements of Discovery
Producer Services LLC, included in this Annual Report (Form 10-K) for the year ended December 31,
2008, filed with the Securities and Exchange Commission.
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/s/ Ernst & Young LLP
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Tulsa, Oklahoma February 27, 2009 |
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exv23w3
Exhibit 23.3
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8
and in Amendment No. 1 to Registration Statements No. 333-142278 and No. 333-146832 on Form S-3 of
our report dated March 4, 2009, relating to the consolidated financial statements and financial
statement schedule of DCP East Texas Holdings, LLC as of December 31, 2008 and 2007 and for the
three years in the period ended December 31, 2008 (which report expresses an unqualified opinion
and includes an explanatory paragraph relating to the preparation of the DCP East Texas Holdings,
LLC consolidated financial statements through July 1, 2007 from the separate records maintained by
DCP Midstream, LLC), appearing in this Annual Report on Form 10-K of DCP Midstream Partners, LP for
the year ended December 31, 2008.
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/s/ Deloitte & Touche LLP
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Denver, Colorado March 4, 2009 |
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exv23w4
Exhibit 23.4
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8
and in Amendment No. 1 to Registration Statements No. 333-142278 and No. 333-146832 on Form S-3 of
our report dated March 4, 2009, relating to the consolidated balance sheet of DCP Midstream GP, LP
(a wholly owned subsidiary of DCP Midstream, LLC) as of December 31, 2008, appearing in this Annual
Report on Form 10-K of DCP Midstream Partners, LP for the year ended December 31, 2008.
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/s/ Deloitte & Touche LLP
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Denver, Colorado March 4, 2009 |
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exv23w5
Exhibit 23.5
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8
and in Amendment No. 1 to Registration Statements No. 333-142278 and No. 333-146832 on Form S-3 of
our report dated February 18, 2009, relating to the consolidated balance sheet of DCP Midstream,
LLC as of December 31, 2008, appearing in this Annual Report on Form 10-K of DCP Midstream
Partners, LP for the year ended December 31, 2008.
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/s/ Deloitte & Touche LLP
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|
Denver, Colorado March 4, 2009 |
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|
exv31w1
Exhibit 31.1
Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
I, Mark A. Borer certify that:
1. I have reviewed this annual report on Form 10-K of DCP Midstream Partners, LP for the fiscal
year ended December 31, 2008;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financials statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting that are reasonably likely to adversely affect the registrants
ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrants internal control over financial reporting.
Date: March 5, 2009
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/s/ Mark A. Borer
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|
|
Mark A. Borer |
|
|
Chief Executive Officer
DCP Midstream GP, LLC |
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|
exv31w2
Exhibit 31.2
Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
I, Angela A. Minas certify that:
1. I have reviewed this annual report on Form 10-K of DCP Midstream Partners, LP for the fiscal
year ended December 31, 2008;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financials statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting that are reasonably likely to adversely affect the registrants
ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrants internal control over financial reporting.
Date: March 5, 2009
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/s/ Angela A. Minas
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Angela A. Minas |
|
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Chief Financial Officer
DCP Midstream GP, LLC |
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exv32w1
Exhibit 32.1
Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
The undersigned, the Chief Executive Officer of DCP Midstream GP, LLC., a Delaware limited
liability company and general partner of DCP Midstream GP, LP, general partner of DCP Midstream
Partners, LP (the Partnership), hereby certifies that, to his knowledge on the date hereof:
(a) the annual report on Form 10-K of the Partnership for the fiscal year ended December 31, 2008,
filed on the date hereof with the Securities and Exchange Commission (the Report) fully complies
with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(b) the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
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/s/ Mark A. Borer
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Mark A. Borer |
|
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Chief Executive Officer March 5, 2009 |
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|
exv32w2
Exhibit 32.2
Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
The undersigned, the Chief Financial Officer of DCP Midstream GP, LLC., a Delaware limited
liability company and general partner of DCP Midstream GP, LP, general partner of DCP Midstream
Partners, LP (the Partnership), hereby certifies that, to his knowledge on the date hereof:
(a) the annual report on Form 10-K of the Partnership for the fiscal year ended December 31, 2008,
filed on the date hereof with the Securities and Exchange Commission (the Report) fully complies
with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(b) the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
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|
|
/s/ Angela A. Minas
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|
|
Angela A. Minas |
|
|
Chief Financial Officer March 5, 2009 |
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|
exv99w1
Exhibit 99.1
DCP Midstream GP, LP
(A Delaware Limited Partnership)
Consolidated Balance Sheet
As of December 31, 2008
CONSOLIDATED BALANCE SHEET OF
DCP MIDSTREAM GP, LP
TABLE OF CONTENTS
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Page |
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Independent Auditors Report |
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2 |
|
Consolidated Balance Sheet as of December 31, 2008 |
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3 |
|
Notes to Consolidated Balance Sheet |
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4 |
|
1
INDEPENDENT
AUDITORS REPORT
To the Board of Directors of
DCP Midstream GP, LLC
Denver, Colorado:
We have audited the accompanying consolidated balance sheet of DCP Midstream GP, LP and
subsidiaries (the Company) (a wholly owned subsidiary of DCP Midstream, LLC) as of December 31,
2008. This financial statement is the responsibility of the Companys management. Our
responsibility is to express an opinion on this financial statement based on our audit. We did not
audit the financial statements of Discovery Producer Services, LLC (Discovery), an investment of
the Company which is accounted for by the use of the equity method. The Companys equity in
Discoverys net assets of $145,054,000 at December 31, 2008 is included in the accompanying
consolidated balance sheet. Discoverys financial statements were audited by other auditors whose
report has been furnished to us, and our opinion, insofar as it relates to amounts included for
Discovery, is based solely on the report of such other auditors.
We conducted our audit in accordance with auditing standards generally accepted in the United
States of America. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An audit includes
consideration of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
balance sheet presentation. We believe that our audit and the report of the other auditors provide
a reasonable basis for our opinion.
In our opinion, based on our audit and the report of the other auditors, such consolidated balance
sheet presents fairly, in all material respects, the financial position of the Company as of
December 31, 2008, in conformity with accounting principles generally accepted in the United States
of America.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 4, 2009
2
DCP MIDSTREAM GP, LP
CONSOLIDATED BALANCE SHEET
|
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|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
ASSETS |
|
|
|
|
Current assets: |
|
|
|
|
Cash and cash equivalents |
|
$ |
48.0 |
|
Accounts receivable: |
|
|
|
|
Trade, net of allowance for doubtful accounts of $0.6 million |
|
|
43.6 |
|
Affiliates |
|
|
36.8 |
|
Inventories |
|
|
20.9 |
|
Unrealized gains on derivative instruments |
|
|
15.4 |
|
Other |
|
|
0.5 |
|
|
|
|
|
Total current assets |
|
|
165.2 |
|
Restricted investments |
|
|
60.2 |
|
Property, plant and equipment, net |
|
|
629.3 |
|
Goodwill |
|
|
88.8 |
|
Intangible assets, net |
|
|
47.7 |
|
Equity method investments |
|
|
175.4 |
|
Unrealized gains on derivative instruments |
|
|
8.6 |
|
Other long-term assets |
|
|
4.8 |
|
|
|
|
|
Total assets |
|
$ |
1,180.0 |
|
|
|
|
|
LIABILITIES AND PARTNERS DEFICIT |
|
|
|
|
Current liabilities: |
|
|
|
|
Accounts payable: |
|
|
|
|
Trade |
|
$ |
44.8 |
|
Affiliates |
|
|
33.6 |
|
Unrealized losses on derivative instruments |
|
|
17.7 |
|
Accrued interest payable |
|
|
1.3 |
|
Other |
|
|
27.4 |
|
|
|
|
|
Total current liabilities |
|
|
124.8 |
|
Long-term debt |
|
|
656.5 |
|
Unrealized losses on derivative instruments |
|
|
26.0 |
|
Other long-term liabilities |
|
|
14.3 |
|
|
|
|
|
Total liabilities |
|
|
821.6 |
|
|
|
|
|
|
|
|
|
|
Non-controlling interests |
|
|
363.7 |
|
|
|
|
|
|
Commitments and contingent liabilities |
|
|
|
|
|
|
|
|
|
Partners deficit: |
|
|
|
|
Partners equity |
|
|
178.2 |
|
Note receivable from DCP Midstream, LLC |
|
|
(183.0 |
) |
Accumulated other comprehensive loss |
|
|
(0.5 |
) |
|
|
|
|
Total partners deficit |
|
|
(5.3 |
) |
|
|
|
|
Total liabilities and partners deficit |
|
$ |
1,180.0 |
|
|
|
|
|
See accompanying notes to consolidated balance sheet.
3
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2008
1. Description of Business and Basis of Presentation
DCP Midstream GP, LP, with its consolidated subsidiaries, or us, we or our, is a Delaware
limited partnership, whose interests are owned by DCP Midstream, LLC and DCP Midstream GP, LLC. We
own approximately a 1% interest in and act as the general partner for DCP Midstream Partners, LP,
or DCP Partners or the partnership, a master limited partnership formed in August 2005, which is
engaged in the business of gathering, compressing, treating, processing, transporting and selling
natural gas, producing, transporting, storing and selling propane and transporting and selling
natural gas liquids, or NGLs, and condensate. DCP Partners operations and activities are managed
by us. We, in turn, are managed by our general partner, DCP Midstream GP, LLC, which we refer to as
our General Partner, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC directs DCP
Partners business operations through their ownership and control of our General Partner. DCP
Midstream, LLC and its affiliates employees provide administrative support to DCP Partners and
operate our assets. DCP Midstream, LLC is owned 50% by Spectra Energy Corp, or Spectra Energy, and
50% by ConocoPhillips.
The partnership includes: our Northern Louisiana system; our Southern Oklahoma system
(acquired in May 2007); our limited liability company interests in DCP East Texas Holdings, LLC, or
East Texas, and Discovery Producer Services LLC, or Discovery (acquired in July 2007); our Wyoming
system and a 70% interest in our Colorado system (each acquired in August 2007); our Michigan
system (acquired in October 2008); our wholesale propane logistics business (acquired in November
2006); and our NGL transportation pipelines.
The consolidated balance sheet has been prepared in accordance with accounting principles
generally accepted in the United States of America, or GAAP. The consolidated balance sheet
includes the accounts of DCP Midstream GP, LP and DCP Partners. We consolidate DCP Partners as we
act as the general partner and as the limited partners do not have substantive kick-out or
participating rights. DCP Partners investments in greater than 20% owned affiliates, which are not
variable interest rights and where DCP Partners does not exercise control, are accounted for using
the equity method. All significant intercompany balances and transactions have been eliminated.
Transactions between us and other DCP Midstream, LLC operations and other affiliates have been
identified in the consolidated balance sheet as transactions between affiliates.
2. Summary of Significant Accounting Policies
Use of Estimates Conformity with GAAP requires management to make estimates and assumptions
that affect the amounts reported in the consolidated balance sheet and notes. Although these
estimates are based on managements best available knowledge of current and expected future events,
actual results could differ from those estimates.
Cash and Cash Equivalents We consider investments in highly liquid financial instruments
purchased with an original stated maturity of 90 days or less to be cash equivalents.
Short-Term and Restricted Investments We may invest available cash balances in various
financial instruments, such as commercial paper, money market instruments and tax-exempt debt
securities that have stated maturities of 20 years or more. These instruments provide for a high
degree of liquidity through features, which allow for the redemption of the investment at its face
amount plus earned income. As we generally intend to sell these instruments within one year or less
from the balance sheet date, and as they are available for use in current operations, they are
classified as current assets, unless otherwise restricted.
Restricted investments are used as collateral to secure the term loan portion of our credit
facility and to finance gathering and compression asset acquisitions. We have classified all
short-term and restricted investments as available-for-sale as we do not intend to hold them to
maturity, nor are they bought or sold with the objective of generating profit on short-term
differences in prices. These investments are recorded at fair value, with changes in fair value
recorded as unrealized gains and losses in accumulated other comprehensive loss, or AOCI. The cost,
including accrued interest on investments, approximates fair value, due to the short-term, highly
liquid nature of the securities held by us, and as interest rates are re-set on a daily, weekly or
monthly basis.
Inventories Inventories, which consist primarily of propane, are recorded at the lower of
weighted-average cost or market value. Transportation costs are included in inventory.
4
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
Gas and NGL Imbalance Accounting Quantities of natural gas or NGLs over-delivered or
under-delivered related to imbalance agreements with customers, producers or pipelines are recorded
monthly as other receivables or other payables using current market prices or the weighted-average
prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of
natural gas or NGLs, or with cash. Included in the consolidated balance sheet as accounts
receivabletrade and accounts receivableaffiliates were imbalances of $3.8 million at December 31,
2008. Included in the consolidated balance sheet as accounts payabletrade were imbalances of $1.4
million at December 31, 2008.
Property, Plant and Equipment Property, plant and equipment are recorded at historical cost.
The cost of maintenance and repairs, which are not significant improvements, are expensed when
incurred. Depreciation is computed using the straight-line method over the estimated useful lives
of the assets.
Asset retirement obligations associated with tangible long-lived assets are recorded at fair
value in the period in which they are incurred, if a reasonable estimate of fair value can be made,
and added to the carrying amount of the associated asset. This additional carrying amount is then
depreciated over the life of the asset. The liability is determined using a risk free interest
rate, and increases due to the passage of time based on the time value of money until the
obligation is settled. We recognize a liability of a conditional asset retirement obligation as
soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement
obligation is defined as an unconditional legal obligation to perform an asset retirement activity
in which the timing and/or method of settlement are conditional on a future event that may or may
not be within the control of the entity.
Goodwill and Intangible Assets Goodwill is the cost of an acquisition less the fair value of
the net assets of the acquired business. We evaluate goodwill for impairment annually in the third
quarter, and whenever events or changes in circumstances indicate it is more likely than not that
the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill
consists of a two-step process. The first step involves comparing the fair value of the reporting
unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the
reporting unit exceeds its fair value, the second step of the process involves comparing the fair
value and carrying value of the goodwill of that reporting unit. If the carrying value of the
goodwill of a reporting unit exceeds the fair value of that goodwill, the excess of the carrying
value over the fair value is recognized as an impairment loss.
Intangible assets consist primarily of customer contracts, including commodity purchase,
transportation and processing contracts and related relationships. These intangible assets are
amortized on a straight-line basis over the period of expected future benefit.
Long-Lived Assets We periodically evaluate whether the carrying value of long-lived assets
has been impaired when circumstances indicate the carrying value of those assets may not be
recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is
not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the
use and eventual disposition of the asset. We consider various factors when determining if these
assets should be evaluated for impairment, including but not limited to:
|
|
|
significant adverse change in legal factors or business climate; |
|
|
|
|
a current-period operating or cash flow loss combined with a history of operating or
cash flow losses, or a projection or forecast that demonstrates continuing losses
associated with the use of a long-lived asset; |
|
|
|
|
an accumulation of costs significantly in excess of the amount originally expected
for the acquisition or construction of a long-lived asset; |
|
|
|
|
significant adverse changes in the extent or manner in which an asset is used, or in
its physical condition; |
|
|
|
|
a significant adverse change in the market value of an asset; or |
|
|
|
|
a current expectation that, more likely than not, an asset will be sold or otherwise
disposed of before the end of its estimated useful life. |
If the carrying value is not recoverable, the impairment loss is measured as the excess of the
assets carrying value over its fair value. We assess the fair value of long-lived assets using
commonly accepted techniques, and may use more than one method, including, but not limited to,
recent third party comparable sales and discounted cash flow models. Significant changes in market
conditions resulting from events such as the condition of an asset or a change in managements
intent to utilize the asset would generally require management to reassess the cash flows related
to the long-lived assets.
Equity Method Investments We use the equity method to account for investments in greater
than 20% owned affiliates that are not variable interest entities and where we do not have the
ability to exercise control, and investments in less than 20% owned affiliates where we have the
ability to exercise significant influence.
5
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
We evaluate our equity method investments for impairment whenever events or changes in
circumstances indicate that the carrying value of such investments may have experienced a decline
in value. When evidence of loss in value has occurred, we compare the estimated fair value of the
investment to the carrying value of the investment to determine whether an impairment has occurred.
We assess the fair value of our equity method investments using commonly accepted techniques, and
may use more than one method, including, but not limited to, recent third party comparable sales
and discounted cash flow models. If the estimated fair value is less than the carrying value, the
excess of the carrying value over the estimated fair value is recognized as an impairment loss.
Unamortized Debt Expense Expenses incurred with the issuance of long-term debt are amortized
over the term of the debt using the effective interest method. These expenses are recorded on the
consolidated balance sheet as other long-term assets.
Accounting for Sales of Units by a Subsidiary We account for sales of units by a subsidiary
by recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of
proceeds received in excess of the carrying value of the units sold. As a result, we have deferred
approximately $5.4 million of gain on sale of common units in DCP Partners, which is included in
other long-term liabilities in the consolidated balance sheet. This gain is related to DCP
Partners sale of common units in June 2007, August 2007 and March 2008. As a result of our
adoption of SFAS 160 on January 1, 2009, we will reclassify the deferred gain relating to this
transaction from long-term liabilities to partners equity in the consolidated balance sheet.
Accounting for Risk Management Activities and Financial Instruments Effective July 1, 2007,
we elected to discontinue using the hedge method of accounting for our commodity cash flow
protection activities. We are using the mark-to-market method of accounting for all commodity
derivative instruments beginning in July 2007. As a result, the remaining net loss deferred in AOCI
will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011,
as the underlying transactions impact earnings.
Each derivative not qualifying for the normal purchases and normal sales exception is recorded
on a gross basis in the consolidated balance sheet at its fair value as unrealized gains or
unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in
our consolidated balance sheet as unrealized gains or unrealized losses on derivative instruments
at fair value until the contractual settlement period impacts earnings.
Prior to July 1, 2007, we designated each energy commodity derivative as either trading or
non-trading. Certain non-trading derivatives were further designated as either a hedge of a
forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset,
liability or firm commitment (fair value hedge), or normal purchases or normal sales, while certain
non-trading derivatives, which are related to asset-based activities, are designated as non-trading
derivative activity. For the periods presented, we did not have any trading derivative activity,
however, we did have cash flow and fair value hedge activity, normal purchases and normal sales
activity, and non-trading derivative activity included in the consolidated balance sheet.
Cash Flow and Fair Value Hedges For derivatives designated as a cash flow hedge or a fair
value hedge, we maintain formal documentation of the hedge. In addition, we formally assess, both
at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is
highly effective in offsetting changes in cash flows or fair values of hedged items. All components
of each derivative gain or loss are included in the assessment of hedge effectiveness, unless
otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated
balance sheet as unrealized gains or unrealized losses on derivative instruments. The effective
portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in
partners equity as AOCI. During the period in which the hedged transaction impacts earnings,
amounts in AOCI associated with the hedged transaction are reclassified to earnings in the same
accounts as the item being hedged. Hedge accounting is discontinued prospectively when it is
determined that the derivative no longer qualifies as an effective hedge, or when it is probable
that the hedged transaction will not occur. When hedge accounting is discontinued because the
derivative no longer qualifies as an effective hedge, the derivative is subject to the
mark-to-market accounting method prospectively. The derivative continues to be carried on the
consolidated balance sheet at its fair value; however, subsequent changes in its fair value are
recognized in current period earnings. Gains and losses related to discontinued hedges that were
previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings,
unless it is probable that the hedged transaction will not occur, in which case, the gains and
losses that were previously deferred in AOCI will be immediately recognized in current period
earnings.
The fair value of a derivative designated as a fair value hedge is recorded for balance sheet
purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain
or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in
earnings in the current period. All derivatives designated and accounted for as fair value hedges
are classified in the same category as the item being hedged in earnings.
6
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
Valuation When available, quoted market prices or prices obtained through external sources
are used to determine a contracts fair value. For contracts with a delivery location or duration
for which quoted market prices are not available, fair value is determined based on pricing models
developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the
potential impact of liquidating open positions in an orderly manner over a reasonable time period
under current conditions. Changes in market prices and management estimates directly affect the
estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates
may change in the near term.
Environmental Expenditures Environmental expenditures are expensed or capitalized as
appropriate, depending upon the future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that do not generate current or future revenue are
expensed. Liabilities for these expenditures are recorded on an undiscounted basis when
environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Environmental liabilities as of December 31, 2008, included in the consolidated balance sheet as
other current liabilities amounted to $1.3 million and as other long-term liabilities amounted to
$0.6 million.
Equity-Based Compensation Equity classified stock-based compensation cost is measured at
fair value, based on the closing common unit price at grant date, and is recognized as expense over
the vesting period. Liability classified stock-based compensation cost is remeasured at each
reporting date at fair value, based on the closing common unit price, and is recognized as expense
over the requisite service period. Compensation expense for awards with graded vesting provisions
is recognized on a straight-line basis over the requisite service period of each separately vesting
portion of the award. Awards granted to non-employees for acquiring, or in conjunction with
selling, goods and services, are measured at the estimated fair value of the goods or services, or
the fair value of the award, whichever is more reliably measured.
Income Taxes We are structured as a limited partnership which is a pass-through entity for
federal income tax purposes.
3. Recent Accounting Pronouncements
Statement of Financial Accounting Standards, or SFAS, No. 162 The Hierarchy of Generally
Accepted Accounting Principles, or SFAS 162 In May 2008, the Financial Accounting Standards
Board, or FASB, issued SFAS 162, which is intended to improve financial reporting by identifying a
consistent framework, or hierarchy, for selecting accounting principles to be used in preparing
financial statements that are presented in conformity with GAAP for nongovernmental entities.
SFAS 162 is effective 60 days following the SECs approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with
Generally Accepted Accounting Principles. We have assessed the impact of the adoption of SFAS 162,
and believe that there will be no impact on our consolidated financial position.
FASB Staff Position, or FSP, No. SFAS 142-3 Determination of the Useful Life of Intangible
Assets, or FSP 142-3 In April 2008, the FASB issued FSP 142-3, which amends the factors that
should be considered in developing renewal or extension assumptions used to determine the useful
life of a recognized intangible. FSP 142-3 is effective for financial statements issued for fiscal
years beginning after December 15, 2008, and interim periods within those fiscal years. We are in
the process of assessing the impact of FSP 142-3, but do not expect a material impact on our
consolidated financial position as a result of adoption.
SFAS No. 161 Disclosures about Derivative Instruments and Hedging Activitiesan amendment of
FASB Statement No. 133, or SFAS 161 In March 2008, the FASB issued SFAS 161, which requires
disclosures of how and why an entity uses derivative instruments, how derivative instruments and
related hedged items are accounted for and how derivative instruments and related hedged items
affect an entitys financial position, financial performance, and cash flows. SFAS 161 is effective
for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our
disclosures, and will make the required disclosures in our 2009 consolidated balance sheet.
SFAS No. 160 Noncontrolling Interests in Consolidated Financial Statements, an amendment of
Accounting Research Bulletin No. 51, or SFAS 160 In December 2007, the FASB issued SFAS 160,
which establishes accounting and reporting standards for ownership interests in subsidiaries held
by parties other than the parent, the amount of consolidated net income attributable to the parent
and to the noncontrolling interest, changes in a parents ownership interest and the valuation of
retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also
establishes reporting requirements that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS 160 was effective for us on January 1, 2009, and did not have a significant impact on our
consolidated financial
7
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
position. As a result of adoption effective January 1, 2009, we will reclassify our
non-controlling interests and the deferred gain relating to the sale of common units in DCP
Partners from long term liabilities to partners equity in the consolidated balance sheet.
SFAS No. 141(R) Business Combinations (revised 2007), or SFAS 141(R) In December 2007, the
FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize
all (and only) the assets acquired and liabilities assumed in the transaction; establishes the
acquisition-date fair value as the measurement objective for all assets acquired and liabilities
assumed; and requires the acquirer to disclose to investors and other users all of the information
they need to evaluate and understand the nature and financial effect of the business combination.
SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively
upon adoption, we will account for all transactions with closing dates subsequent to the adoption
date in accordance with the provisions of the standard.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilitiesincluding
an amendment of FAS 115, or SFAS 159 In February 2007, the FASB issued SFAS 159, which allows
entities to choose, at specified election dates, to measure eligible financial assets and
liabilities at fair value that are not otherwise required to be measured at fair value. If a
company elects the fair value option for an eligible item, changes in that items fair value in
subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes
presentation and disclosure requirements designed to draw comparison between entities that elect
different measurement attributes for similar assets and liabilities. The provisions of SFAS 159
became effective for us on January 1, 2008. We have not elected the fair value option relative to
any of our financial assets and liabilities which are not otherwise required to be measured at fair
value by other accounting standards. Therefore, there is no effect of adoption reflected in our
consolidated financial position.
SFAS No. 157, Fair Value Measurements, or SFAS 157 In September 2006, the FASB issued SFAS
157, which was effective for us on January 1, 2008. SFAS 157:
|
|
|
defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the
measurement date; |
|
|
|
|
establishes a framework for measuring fair value; |
|
|
|
|
establishes a three-level hierarchy for fair value measurements based upon the
transparency of inputs to the valuation of an asset or liability as of the measurement
date; |
|
|
|
|
nullifies the guidance in Emerging Issues Task Force, or EITF, 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy
Trading and Risk Management Activities, which required the deferral of profit at inception
of a transaction involving a derivative financial instrument in the absence of observable
data supporting the valuation technique; and |
|
|
|
|
significantly expands the disclosure requirements around instruments measured at fair
value. |
Upon the adoption of this standard we incorporated the marketplace participant view as
prescribed by SFAS 157. Such changes included, but were not limited to, changes in valuation
policies to reflect an exit price methodology, the effect of considering our own non-performance
risk on the valuation of liabilities, and the effect of any change in our credit rating or
standing. As a result of adopting SFAS 157, we recorded a transition adjustment of
approximately $5.8 million as an increase to earnings and an insignificant amount as an increase to AOCI
during the three months ended March 31, 2008. All changes in our valuation methodology have been
incorporated into our fair value calculations subsequent to adoption.
Pursuant to FASB Staff Position 157-2, the FASB issued a partial deferral, ending on December
31, 2008, of the implementation of SFAS 157 as it relates to all non-financial assets and
liabilities where fair value is the required measurement attribute by other accounting standards.
While we have adopted SFAS 157 for all financial assets and liabilities effective January 1, 2008,
we are in the process of assessing the impact SFAS 157 will have on our non-financial assets and
liabilities, but do not expect a material impact on our consolidated financial position upon
adoption.
FSP No. 157-3 Determining the Fair Value of a Financial Asset When the Market for That Asset
is Not Active, or FSP 157-3 In October 2008, the FASB issued FSP 157-3, which provides guidance
in situations where a) observable inputs do not exist, b) observable inputs exist but only in an
inactive market and c) how market quotes should be considered when assessing the relevance of
observable and unobservable inputs to determine fair value. FSP 157-3 was effective upon issuance,
including prior periods for which financial statements have not been issued. We believe that the
financial assets that are reflected in our financial statements are transacted within active
markets, and therefore, there is no effect on our financial position as a result of the adoption of
this FSP.
FSP of Financial Interpretation, or FIN, 39-1, Amendment of FASB Interpretation No. 39, or
FSP FIN 39-1 In April 2007, the FASB issued FSP FIN 39-1, which permits, but does not require, a
reporting entity to offset fair value amounts recognized
8
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
for the right to reclaim cash collateral
(a receivable) or the obligation to return cash collateral (a payable) against the fair value
amounts recognized for derivative instruments executed with the same counterparty under a master
netting arrangement. FSP FIN 39-1 became effective for us beginning on January 1, 2008; however, we
have elected to continue our policy of reflecting our derivative asset and liability positions, as
well as any cash collateral, on a gross basis in our consolidated balance sheet.
EITF 08-06 Equity Method Investment Accounting Considerations, or EITF 08-06 In November
2008, the Emerging Issues Task Force issued ETIF 08-06. Although the issuance of FAS 141(R) and FAS
160 were not intended to reconsider the accounting for equity method investments, the application
of the equity method is affected by the issuance of these standards. This issue addresses a) how
the initial carrying value of an equity method investment should be determined; b) how an
impairment assessment of an underlying indefinite-lived intangible asset of an equity method
investment should be performed; c) how an equity method investees issuance of shares should be
accounted for and d) how to account for a change in an investment from the equity method to the
cost method. This issue is effective for our Company effective January 1, 2009, and although we do
not expect any changes to the manner in which we apply equity method accounting, this guidance will
be considered on a prospective basis to transactions with equity method investees.
4. Acquisitions
Gathering and Compression Assets
On October 1, 2008, we acquired
Michigan Pipeline & Processing, LLC, or MPP, a privately held company engaged in natural gas gathering
and treating services for natural gas produced from the Antrim Shale of northern Michigan and
natural gas transportation within Michigan. Under the terms of the acquisition, we paid a purchase
price of $145.0 million, plus net working capital and other adjustments of $3.4 million, subject to
additional customary purchase price adjustments. We may pay up to an additional $15.0 million to
the sellers depending on the earnings of the assets after a three-year period. We financed the
acquisition through utilization of our credit facility. In addition, we entered into a separate
agreement that provides the seller with available treating capacity on certain Michigan assets. The
seller agreed to pay up to $1.5 million annually for up to nine years if they do not meet certain
criteria, including providing additional volumes for treatment. These payments would reduce
goodwill as a return of purchase price. This agreement may be terminated earlier if certain
performance criteria of Michigan assets are satisfied. Certain of these performance criteria were
satisfied, and as a result, the amount was reduced to approximately $0.8 million per year as of
December 31, 2008. We initially held a $25.0 million letter of credit to secure the sellers
performance under this agreement and to secure the sellers indemnification obligation under the
acquisition agreement; however as a result of the satisfaction of certain performance conditions,
this amount was reduced to approximately $22.5 million as of December 31, 2008. The fees under the
Omnibus Agreement increased $0.4 million per year effective October 1, 2008, in connection with the
acquisition.
Under the purchase method of accounting, the assets and liabilities of MPP were recorded at
their respective fair values as of the date of the acquisition, and we recorded goodwill of
approximately $6.7 million. The goodwill amount recognized relates primarily to projected growth
from new customers. The values of certain assets and liabilities are preliminary, and are subject
to adjustment as additional information is obtained, which when finalized may result in material
adjustments. The purchase price allocation is as follows:
|
|
|
|
|
|
|
(Millions) |
|
Cash |
|
$ |
1.7 |
|
Accounts receivable |
|
|
2.1 |
|
Other assets |
|
|
0.1 |
|
Other long term assets |
|
|
3.8 |
|
Property, plant and equipment |
|
|
116.1 |
|
Goodwill |
|
|
6.7 |
|
Intangible assets |
|
|
20.0 |
|
Other liabilities |
|
|
(0.5 |
) |
Non-controlling interest in joint venture |
|
|
(1.6 |
) |
|
|
|
|
Total purchase price allocation |
|
$ |
148.4 |
|
|
|
|
|
9
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
5. Agreements and Transactions with Affiliates
DCP Midstream, LLC
Omnibus Agreement
We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP
Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for
salaries of operating personnel and employee benefits as well as capital expenditures, maintenance
and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We
also pay DCP Midstream, LLC an annual fee for centralized corporate functions performed by DCP
Midstream, LLC on our behalf, including legal, accounting, cash management, insurance
administration and claims processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll, taxes and engineering. Under the Omnibus
Agreement, DCP Midstream, LLC provided parental guarantees, totaling $43.0 million at December 31,
2008, to certain counterparties to our commodity derivative instruments.
All of the fees under the Omnibus Agreement are subject to adjustment annually for changes in
the Consumer Price Index.
The Omnibus Agreement also addresses the following matters:
|
|
|
DCP Midstream, LLCs obligation to indemnify us for certain liabilities and our
obligation to indemnify DCP Midstream, LLC for certain liabilities; |
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its credit support, including
without limitation guarantees and letters of credit, for our obligations related to
derivative financial instruments, such as commodity price hedging contracts, to the
extent that such credit support arrangements were in effect as of the closing of our
initial public offering in December 2005, until the earlier to occur of the fifth
anniversary of the closing of our initial public offering or such time as we obtain an
investment grade credit rating from either Moodys Investor Services, Inc. or Standard &
Poors Ratings Group with respect to any of our unsecured indebtedness; and |
|
|
|
|
DCP Midstream, LLCs obligation to continue to maintain its credit support, including
without limitation guarantees and letters of credit, for our obligations related to
commercial contracts with respect to its business or operations that were in effect at
the closing of our initial public offering until the expiration of such contracts. |
Any or all of the provisions of the Omnibus Agreement, other than the indemnification
provisions, will be terminable by DCP Midstream, LLC at its option if the general partner is
removed without cause and units held by the general partner and its affiliates are not voted in
favor of that removal. The Omnibus Agreement will also terminate in the event of a change of
control of us, the general partner (DCP Midstream GP, LP) or the General Partner (DCP Midstream GP,
LLC).
Competition
None of DCP Midstream, LLC, nor any of its affiliates, including Spectra Energy and
ConocoPhillips, is restricted, under either the partnership agreement or the Omnibus Agreement,
from competing with us. DCP Midstream, LLC and any of its affiliates, including Spectra Energy and
ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in
the future without any obligation to offer us the opportunity to purchase or construct those
assets.
Indemnification
The Black Lake pipeline has experienced increased operating costs due to pipeline integrity
testing that commenced in 2005 and was completed during the second quarter of 2008. Testing
revealed irregularities, the more severe of which were repaired in October 2008 and the less severe
of which are scheduled for repair in 2009. DCP Midstream, LLC has agreed to indemnify us for up to
$5.3 million of our pro rata share of any capital contributions associated with repairing the Black
Lake pipeline that are determined to be necessary as a result of the pipeline integrity testing. We
anticipate repairs of approximately $0.8 million on the pipeline, which will be funded directly
from Black Lake. We will not make contributions to Black Lake to cover these expenses.
In connection with our acquisition of our wholesale propane logistics business, DCP Midstream,
LLC agreed to indemnify us until October 31, 2009 for any claims for fines or penalties of any
governmental authority for periods prior to the closing, agreed to indemnify us until October 31,
2010 if certain contractual matters result in a claim, and agreed to indemnify us indefinitely for
breaches of the agreement. The indemnity obligation for breach of the representations and
warranties is not effective until claims
exceed in the aggregate $680,000 and is subject to a maximum liability of $6.8 million. This
indemnity obligation for all other claims
10
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
other than a breach of the representations and warranties
does not become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisitions of East Texas and Discovery from DCP Midstream, LLC, DCP
Midstream, LLC agreed to indemnify us until July 1, 2009 for any claims for fines or penalties of
any governmental authority for periods prior to the closing and that are associated with certain
East Texas assets that were formerly owned by Gulf South and UP Fuels, and agreed to indemnify us
indefinitely for breaches of the agreement and certain existing claims. The indemnity obligation
for breach of the representations and warranties is not effective until claims exceed in the
aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity
obligation for all other claims other than a breach of the representations and warranties does not
become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisition of certain subsidiaries of Momentum Energy Group, Inc., or
MEG, DCP Midstream, LLC agreed to indemnify us until August 29, 2008 for any breach of the
representations and warranties (except certain corporate related matters that survive
indefinitely), and indefinitely for breaches of the agreement.
We have not pursued indemnification under these agreements.
Other Agreements and Transactions with DCP Midstream, LLC
DCP Midstream, LLC owns certain assets and is party to certain contractual relationships
around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC
is able to source natural gas upstream of Pelico and deliver it to the inlet of the Pelico system,
and is able to take natural gas from the outlet of the Pelico system and market it downstream of
Pelico. Because of DCP Midstream, LLCs ability to move natural gas around Pelico, there are
certain contractual relationships around Pelico that define how natural gas is bought and sold
between us and DCP Midstream, LLC. The agreement is described below:
|
|
|
DCP Midstream, LLC will supply Pelicos system requirements that exceed its on-system
supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our
Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition
cost plus transportation service charges incurred. |
|
|
|
|
If our Pelico system has volumes in excess of the on-system demand, DCP Midstream,
LLC will purchase the excess natural gas from us and transport it to sales points at an
index-based price, less a contractually agreed-to marketing fee. |
|
|
|
|
In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at
certain Pelico outlets for a price that equals the original Pelico purchase price from
DCP Midstream, LLC, plus a portion of the index differential between upstream sources to
certain downstream indices with a maximum differential and a minimum differential, plus
a fixed fuel charge and other related adjustments. |
In addition, we sell NGLs processed at our Minden and Ada plants,
and sell
condensate removed from the
gas gathering systems that deliver to the Minden and Ada plants, and from our Pelico system to a
subsidiary of DCP Midstream, LLC equal to that subsidiarys net weighted-average sales price,
adjusted for transportation, processing and other charges from the tailgate of the respective asset. We also
sell propane to a subsidiary of DCP Midstream, LLC.
We also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides
that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze pipeline, pursuant to a
fee-based rate that will be applied to the volumes transported. DCP Midstream, LLC is the sole
shipper on the Seabreeze pipeline under a transportation agreement.
In December 2006, we completed construction of our Wilbreeze pipeline, which connects a DCP
Midstream, LLC gas processing plant to our Seabreeze pipeline. The project is supported by an NGL
product dedication agreement with DCP Midstream, LLC.
We anticipate continuing to purchase commodities from and sell commodities to DCP Midstream,
LLC in the ordinary course of business.
In conjunction with our acquisition of a 40% limited liability company interest in Discovery
from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC
whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for certain
Discovery capital projects, which were forecasted to be completed prior to our acquisition of a 40%
limited liability company interest in Discovery. Pursuant to the letter agreement, DCP
Midstream, LLC made capital contributions to us of $3.8 million during 2008, to reimburse us for
these capital projects.
11
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
We have a note receivable from DCP Midstream, LLC totaling $183.0 million. This note is due on
demand; however, we do not anticipate requiring DCP Midstream, LLC to repay this amount.
Accordingly we have reflected this receivable as a component of partners deficit. The note
receivable bears interest at the greater of 5.00% or the applicable federal rate in effect under
section 1274(d) of the Internal Revenue Code of 1986. The interest rate in effect on the note was
5.00% at December 31, 2008. All interest income earned under the note has been distributed to DCP
Midstream, LLC.
In accordance with our partnership agreement, we distribute all available cash to our partners
according to their respective ownership interest.
Spectra Energy
We purchase a portion of our propane from and market propane on behalf of Spectra Energy. We
anticipate continuing to purchase propane from and market propane on behalf of Spectra Energy in
the ordinary course of business.
During the second quarter of 2008, we entered into a propane supply agreement with Spectra
Energy. This agreement, effective May 1, 2008 and terminating April 30, 2014, provides us propane
supply at our marine terminal, which is included in our Wholesale Propane Logistics segment, for up
to approximately 120 million gallons of propane annually. This contract replaces the supply
provided under a contract with a third party that was terminated for non-performance during the
first quarter of 2008.
ConocoPhillips
We have multiple agreements whereby we provide a variety of services to ConocoPhillips and its
affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing
arrangements, gas purchase and gas sales agreements. We anticipate continuing to purchase from and
sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In
addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is
performed by us. We received $1.9 million of capital reimbursements during the year ended December
31, 2008.
We had accounts receivable and accounts payable with affiliates as follows:
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
|
(Millions) |
DCP Midstream, LLC: |
|
|
|
|
Accounts receivable |
|
$ |
30.3 |
|
Accounts payable |
|
$ |
27.9 |
|
Spectra Energy: |
|
|
|
|
Accounts receivable |
|
$ |
4.0 |
|
Accounts payable |
|
$ |
5.3 |
|
ConocoPhillips: |
|
|
|
|
Accounts receivable |
|
$ |
2.5 |
|
Accounts payable |
|
$ |
0.4 |
|
The following summarizes the unrealized losses on derivative instruments with affiliates:
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
|
(Millions) |
DCP Midstream, LLC: |
|
|
|
|
Unrealized lossescurrent |
|
$ |
(1.2 |
) |
12
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
6. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
|
|
|
|
|
|
|
|
|
Depreciable |
|
December 31, |
|
|
|
Life |
|
2008 |
|
|
|
|
|
(Millions) |
|
Gathering systems |
|
15 30 Years |
|
$ |
405.0 |
|
Processing plants |
|
25 30 Years |
|
|
163.4 |
|
Terminals |
|
25 30 Years |
|
|
28.5 |
|
Transportation |
|
25 30 Years |
|
|
174.0 |
|
General plant |
|
3 5 Years |
|
|
6.0 |
|
Construction work in progress |
|
|
|
|
43.5 |
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
820.4 |
|
Accumulated depreciation |
|
|
|
|
(191.1 |
) |
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
$ |
629.3 |
|
|
|
|
|
|
|
The above amounts include accrued capital expenditures of $12.3 million as of December 31,
2008, which are included in other current liabilities in the consolidated balance sheet.
We lease one of our Michigan transmission pipelines to a third party under a long-term
contract. The carrying value of the pipeline is approximately $23.0 million, with accumulated
depreciation of $0.2 million. Minimum future non-cancelable rental payments are as follows:
|
|
|
|
|
Rental Payments |
|
(Millions) |
|
2009 |
|
$ |
3.0 |
|
2010 |
|
|
2.9 |
|
2011 |
|
|
2.9 |
|
2012 |
|
|
2.8 |
|
2013 |
|
|
2.3 |
|
Thereafter |
|
|
20.7 |
|
|
|
|
|
Total |
|
$ |
34.6 |
|
|
|
|
|
Asset Retirement Obligations Our asset retirement obligations relate primarily to the
retirement of various gathering pipelines and processing facilities, obligations related to
right-of-way easement agreements, and contractual leases for land use. We adjust our asset
retirement obligation each quarter for any liabilities incurred or settled during the period,
accretion expense and any revisions made to the estimated cash flows. The asset retirement
obligation, included in other long-term liabilities in the consolidated balance sheet, was $7.9
million at December 31, 2008.
We identified various assets as having an indeterminate life, for which there is no
requirement to establish a fair value for future retirement obligations associated with such
assets. These assets include certain pipelines, gathering systems and processing facilities. A
liability for these asset retirement obligations will be recorded only if and when a future
retirement obligation with a determinable life is identified. These assets have an indeterminate
life because they are owned and will operate for an indeterminate future period when properly
maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified
or dismantled, we would be legally required to remove the asbestos. We currently have no plans to
take actions that would require the removal of the asbestos in these assets. Accordingly, the fair
value of the asset retirement obligation related to this asbestos cannot be estimated and no
obligation has been recorded.
13
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
7. Goodwill and Intangible Assets
The change in the carrying amount of goodwill is as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
Beginning of period |
|
$ |
80.2 |
|
Acquisitions |
|
|
8.6 |
|
|
|
|
|
End of period |
|
$ |
88.8 |
|
|
|
|
|
Goodwill increased during 2008 by $6.7 million as a result of the MPP acquisition, and by $1.9
million for the final purchase price allocation for the MEG subsidiaries acquired from DCP
Midstream, LLC.
We perform an annual goodwill impairment test, and update the test during interim periods if
events or circumstances occur that would more likely than not reduce the fair value of a reporting
unit below its carrying amount. We use a discounted cash flow analysis supported by market
valuation multiples to perform the assessment. Key assumptions in the analysis include the use of
an appropriate discount rate, estimated future cash flows and an estimated run rate of general and
administrative costs. In estimating cash flows, we incorporate current market information, as well
as historical and other factors, into our forecasted commodity prices. Our annual goodwill
impairment tests indicated that our reporting units fair value exceeded its carrying or book
value.
During the fourth quarter of 2008, as a result of the decline in the general equity market
indices and in DCP Midstream Partners, LPs unit price on the New York Stock exchange, we updated
our fair value analysis using current marketplace assumptions and concluded that the carrying value
of goodwill is recoverable; therefore, we did not record any impairment charges during the year
ended December 31, 2008. However, given the current volatility in the equity market, as well as
volatile commodity prices, we will continue to monitor the recoverability of such amounts.
Continued volatility and marketplace activity may alter our conclusion in the future, and could
result in the recognition of an impairment charge.
Intangible assets consist of customer contracts, including commodity purchase, transportation
and processing contracts, and related relationships. The gross carrying amount and accumulated
amortization of these intangible assets are included in the accompanying consolidated balance sheet
as intangible assets, net, and are as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
Gross carrying amount |
|
$ |
52.5 |
|
Accumulated amortization |
|
|
(4.8 |
) |
|
|
|
|
Intangible assets, net |
|
$ |
47.7 |
|
|
|
|
|
Intangible assets increased in 2008 as a result of the MPP acquisition.
As of December 31, 2008, the remaining amortization periods range from approximately less than
one year to 25 years, with a weighted-average remaining period of approximately 21 years.
14
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
8. Equity Method Investments
The following table summarizes our equity method investments:
|
|
|
|
|
|
|
|
|
|
|
Percentage of |
|
|
Carrying |
|
|
|
Ownership as of |
|
|
Value as of |
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2008 |
|
|
|
|
|
|
|
(Millions) |
|
Discovery
Producer Services LLC |
|
|
40 |
% |
|
$ |
105.0 |
|
DCP East Texas Holdings, LLC |
|
|
25 |
% |
|
|
63.9 |
|
Black Lake Pipe Line Company |
|
|
45 |
% |
|
|
6.3 |
|
Other |
|
|
50 |
% |
|
|
0.2 |
|
|
|
|
|
|
|
|
|
Total equity method investments |
|
|
|
|
|
$ |
175.4 |
|
|
|
|
|
|
|
|
|
Discovery operates a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana,
a natural gas liquids fractionator plant near Paradis, Louisiana, a natural gas pipeline from
offshore deep water in the Gulf of Mexico that transports gas to its processing plant in Larose,
Louisiana with a design capacity of 600 MMcf/d and approximately 280 miles of pipe, and several
laterals in the Gulf of Mexico. There was a deficit between the carrying amount of the investment
and the underlying equity of Discovery of $39.7 million at December 31, 2008, which is associated
with, and is being accreted over, the life of the underlying long-lived assets of Discovery.
East Texas is engaged in the business of gathering, transporting, treating, compressing,
processing, and fractionating natural gas and NGLs. Its operations, located near Carthage, Texas,
include a natural gas processing complex with a total capacity of 780 MMcf/d and a natural gas liquids fractionator. The facility is
connected to an approximately 900-mile gathering system, as well as third party gathering systems.
The complex includes and is adjacent to the Carthage Hub, which delivers residue gas to interstate
and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 Bcf/d, acts
as a key exchange point for the purchase and sale of residue gas.
Black Lake owns a 317-mile NGL pipeline, with a throughput capacity of approximately 40
MBbls/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. There was a
deficit between the carrying amount of the investment and the underlying equity of Black Lake of
$6.0 million at December 31, 2008, which is associated with, and is being accreted over, the life
of the underlying long-lived assets of Black Lake.
15
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
The following summarizes balance sheet information of our equity method investments:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
Balance sheet: |
|
|
|
|
Current assets |
|
$ |
104.3 |
|
Long-term assets |
|
|
646.3 |
|
Current liabilities |
|
|
(84.4 |
) |
Long-term liabilities |
|
|
(22.4 |
) |
|
|
|
|
Net assets |
|
$ |
643.8 |
|
|
|
|
|
9. Fair Value Measurement
Determination of Fair Value
Below is a general description of our valuation methodologies for derivative financial assets
and liabilities, as well as short-term and restricted investments, which are measured at fair
value. Fair values are generally based upon quoted market prices, where available. In the event
that listed market prices or quotes are not available, we determine fair value based upon a market
quote, adjusted by other market-based or independently sourced market data such as historical
commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations.
These adjustments result in a fair value for each asset or liability under an exit price
methodology, in line with how we believe a marketplace participant would value that asset or
liability. These adjustments may include amounts to reflect counterparty credit quality, the effect
of our own creditworthiness, the time value of money and/or the liquidity of the market.
|
|
|
Counterparty credit valuation adjustments are necessary when the market price of an
instrument is not indicative of the fair value as a result of the credit quality of the
counterparty. Generally, market quotes assume that all counterparties have near zero, or
low, default rates and have equal credit quality. Therefore, an adjustment may be necessary
to reflect the credit quality of a specific counterparty to determine the fair value of the
instrument. We record counterparty credit valuation adjustments on all derivatives that are
in a net asset position as of the measurement date in accordance with our established
counterparty credit policy, which takes into account any collateral margin that a
counterparty may have posted with us. |
|
|
|
|
Entity valuation adjustments are necessary to reflect the effect of our own credit
quality on the fair value of our net liability position with each counterparty. This
adjustment takes into account any credit enhancements, such as collateral margin we may
have posted with a counterparty, as well as any letters of credit that we have provided.
The methodology to determine this adjustment is consistent with how we evaluate
counterparty credit risk, taking into account our own credit rating, current credit
spreads, as well as any change in such spreads since the last measurement date. |
|
|
|
|
Liquidity valuation adjustments are necessary when we are not able to observe a recent
market price for financial instruments that trade in less active markets for the fair value
to reflect the cost of exiting the position. Exchange traded contracts are valued at market
value without making any additional valuation adjustments and, therefore, no liquidity
reserve is applied. For contracts other than exchange traded instruments, we mark our
positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon
our total net position. We believe that such practice results in the most reliable fair
value measurement as viewed by a market participant. |
We manage our derivative instruments on a portfolio basis and the valuation adjustments
described above are calculated on this basis. We believe that the portfolio level approach
represents the highest and best use for these assets as there are benefits inherent in naturally
offsetting positions within the portfolio at any given time, and this approach is consistent with
how a market participant would view and value the assets. Although we take a portfolio approach to
managing these assets/liabilities, in order to reflect the fair value of any one individual
contract within the portfolio, we allocate all valuation adjustments down to the contract level, to
the extent deemed necessary, based upon either the notional contract volume, or the contract value,
whichever is more applicable.
The methods described above may produce a fair value calculation that may not be indicative of
net realizable value or reflective of future fair values. While we believe that our valuation
methods are appropriate and consistent with other marketplace participants, we recognize that the
use of different methodologies or assumptions to determine the fair value of certain financial
instruments could result in a different estimate of fair value at the reporting date. We review our
fair value policies on a regular basis taking into
16
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
consideration changes in the marketplace and, if necessary, will adjust our policies
accordingly. See Note 14 Risk Management Activities Credit Risk and Financial Instruments.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation
hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of
the measurement date. The three levels are defined as follows.
|
|
|
Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in
active markets. |
|
|
|
|
Level 2 inputs include quoted prices for similar assets and liabilities in active
markets, and inputs that are observable for the asset or liability, either directly or
indirectly, for substantially the full term of the financial instrument. |
|
|
|
|
Level 3 inputs are unobservable and considered significant to the fair value
measurement. |
A financial instruments categorization within the hierarchy is based upon the lowest level of
input that is significant to the fair value measurement. Following is a description of the
valuation methodologies used as well as the general classification of such instruments pursuant to
the hierarchy.
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include over the
counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.
Within our Natural Gas Services segment we typically use OTC derivative contracts in order to
mitigate a portion of our exposure to natural gas, NGL and condensate price changes. These
instruments are generally classified as Level 2. Depending upon market conditions and our strategy,
we may enter into OTC derivative positions with a significant time horizon to maturity, and market
prices for these OTC derivatives may only be readily observable for a portion of the duration of
the instrument. In order to calculate the fair value of these instruments, readily observable
market information is utilized to the extent that it is available; however, in the event that
readily observable market data is not available, we may interpolate or extrapolate based upon
observable data. In instances where we utilize an interpolated or extrapolated value, and it is
considered significant to the valuation of the contract as a whole, we would classify the
instrument within Level 3.
Within our Wholesale Propane Logistics segment, we may enter into a variety of financial
instruments to either secure sales or purchase prices, or capture a variety of market
opportunities. Since financial instruments for NGLs tend to be counterparty and location specific,
we primarily use the OTC derivative instrument markets, which are not as active and liquid as
exchange traded instruments. Market quotes for such contracts may only be available for short dated
positions (up to six months), and a market itself may not exist beyond such time horizon. Contracts
entered into with a relatively short time horizon for which prices are readily observable in the
OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which
we internally generate a forward curve to value such instruments, are generally classified within
Level 3. The internally generated curve may utilize a variety of assumptions including, but not
limited to, historical and future expected correlation of NGL prices to crude oil prices, the
knowledge of expected supply sources coming on line, expected weather trends within certain regions
of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial
quarter depending upon the extent to which the valuation inputs are observable. Generally, an
instrument will move toward a level within the hierarchy that requires a lower degree of judgment
as the time to maturity approaches, and as the markets in which the asset trades will likely become
more liquid and prices more readily available in the market, thus reducing the need to rely upon
our internally developed assumptions. However, the level of a given instrument may change, in
either direction, depending upon market conditions and the availability of market observable data.
Interest Rate Derivative Assets and Liabilities
We have interest rate swap agreements as part of our overall capital strategy. These
instruments effectively exchange a portion of our floating rate debt for fixed rate debt, and are
held with major financial institutions, which are expected to fully perform under the terms of our
agreements. The swaps are generally priced based upon a United States Treasury instrument with
similar duration, adjusted by the credit spread between our company and the United States Treasury
instrument. Given that a significant portion of the swap value is derived from the credit spread,
which may be observed by comparing similar assets in the market, these instruments are classified
within Level 2. Default risk on either side of the swap transaction is also considered in the
valuation. We record
17
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
counterparty credit, our entity valuation, as well as liquidity reserves in the valuation of
our interest rate swaps; however, these reserves are not considered to be a significant input to
the overall valuation.
Short-Term and Restricted Investments
We are required to post collateral to secure the term loan portion of our credit facility, and
may elect to invest a portion of our available cash balances in various financial instruments such
as commercial paper, money market instruments and highly rated tax-exempt debt securities that have
stated maturities of 20 years or more, which are categorized as available-for-sale securities. The
money market instruments are generally priced at acquisition cost, plus accreted interest at the
stated rate, which approximates fair value, without any additional adjustments. Given that there is
no observable exchange traded market for identical money market securities, we have classified
these instruments within Level 2. Investments in commercial paper and highly rated tax-exempt debt
securities are priced using a yield curve for similarly rated instruments, and are classified
within Level 2. As of December 31, 2008, nearly all of our short-term and restricted investments
were held in the form of money market securities. By virtue of our balances in these funds on
September 19, 2008, all of these investments are eligible for, and the funds are participating in,
the U.S. Treasury Departments Temporary Guarantee Program for Money Market Funds.
The following table presents the financial instruments carried at fair value as of December
31, 2008, by consolidated balance sheet caption and by valuation hierarchy, as described above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal Models |
|
Internal Models |
|
|
|
|
Quoted Market |
|
With Significant |
|
With Significant |
|
|
|
|
Prices In |
|
Observable |
|
Unobservable |
|
|
|
|
Active Markets |
|
Market Inputs |
|
Market Inputs |
|
Total Carrying |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Value |
|
|
(Millions) |
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments (a) |
|
$ |
|
|
|
$ |
15.1 |
|
|
$ |
0.3 |
|
|
$ |
15.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted investments |
|
$ |
|
|
|
$ |
60.2 |
|
|
$ |
|
|
|
$ |
60.2 |
|
Commodity derivative instruments (b) |
|
$ |
|
|
|
$ |
6.9 |
|
|
$ |
1.7 |
|
|
$ |
8.6 |
|
Interest rate instruments (b) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities (c): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments |
|
$ |
|
|
|
$ |
(1.2 |
) |
|
$ |
|
|
|
$ |
(1.2 |
) |
Interest rate instruments |
|
$ |
|
|
|
$ |
(16.5 |
) |
|
$ |
|
|
|
$ |
(16.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities (d): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments |
|
$ |
|
|
|
$ |
(3.2 |
) |
|
$ |
|
|
|
$ |
(3.2 |
) |
Interest rate instruments |
|
$ |
|
|
|
$ |
(22.8 |
) |
|
$ |
|
|
|
$ |
(22.8 |
) |
|
|
|
(a) |
|
Included in current unrealized gains on derivative instruments in our consolidated
balance sheet. |
|
(b) |
|
Included in long-term unrealized gains on derivative instruments in our consolidated
balance sheet. |
|
(c) |
|
Included in current unrealized losses on derivative instruments in our consolidated
balance sheet. |
|
(d) |
|
Included in long-term unrealized losses on derivative instruments in our consolidated
balance sheet. |
Changes in Level 3 Fair Value Measurements
The table below illustrates a rollforward of the amounts included in our consolidated balance
sheet for derivative financial instruments that we have classified within Level 3. The
determination to classify a financial instrument within Level 3 is based upon the significance of
the unobservable factors used in determining the overall fair value of the instrument. Since
financial instruments classified as Level 3 typically include a combination of observable
components (that is, components that are actively quoted and can be validated to external sources)
and unobservable components, the gains and losses in the table below may include changes in fair
value due in part to observable market factors, or changes to our assumptions on the unobservable
components. Depending upon the information readily observable in the market, and/or the use of
unobservable inputs, which are significant to the overall valuation, the classification of any
individual financial instrument may differ from one measurement date to the next. In the event that
there is a
18
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
movement to/from the classification of an instrument as Level 3, we have reflected such items
in the table below within the Transfers In/Out of Level 3 caption.
We manage our overall risk at the portfolio level, and in the execution of our strategy, we
may use a combination of financial instruments, which may be classified within any level. Since
Level 1 and Level 2 risk management instruments are not included in the rollforward below, the
gains or losses in the table do not reflect the effect of our total risk management activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Realized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and Unrealized |
|
|
|
|
|
Purchases, |
|
|
|
|
Balance at |
|
Gains (Losses) |
|
Transfers In/ |
|
Issuances and |
|
Balance at |
|
|
December 31, |
|
Included in |
|
Out of |
|
Settlements, |
|
December 31, |
|
|
2007 |
|
Earnings |
|
Level 3 (a) |
|
Net |
|
2008 |
|
|
(Millions) |
Commodity derivative
instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
0.2 |
|
|
$ |
0.8 |
|
|
$ |
|
|
|
$ |
(0.7 |
) |
|
$ |
0.3 |
|
Long-term assets |
|
$ |
1.5 |
|
|
$ |
1.0 |
|
|
$ |
(0.8 |
) |
|
$ |
|
|
|
$ |
1.7 |
|
Current liabilities |
|
$ |
(1.6 |
) |
|
$ |
(0.2 |
) |
|
$ |
|
|
|
$ |
1.8 |
|
|
$ |
|
|
Long-term liabilities |
|
$ |
(0.2 |
) |
|
$ |
0.2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
(a) |
|
Amounts transferred in are reflected at fair value as of the end of the period and amounts
transferred out are reflected at fair value at the beginning of the period. |
10. Estimated Fair Value of Financial Instruments
We have determined the fair value amounts using available market information and appropriate
valuation methodologies. However, considerable judgment is required in interpreting market data to
develop the estimates of fair value. Accordingly, the estimates presented herein are not
necessarily indicative of the amounts that we could realize in a current market exchange. The use
of different market assumptions and/or estimation methods may have a material effect on the
estimated fair value amounts.
The fair value of restricted investments, accounts receivable and accounts payable are not
materially different from their carrying amounts because of the short term nature of these
instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses
on derivative instruments are carried at fair value. The carrying value of long-term debt
approximates fair value, as the interest rate is variable and reflects current market conditions.
11. Debt
Long-term debt was as follows:
|
|
|
|
|
|
|
Principal |
|
|
|
Amount at |
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
Revolving credit facility, weighed-average interest rate of
2.08%, due June 21, 2012 (a) |
|
$ |
596.5 |
|
Term loan facility, interest rate of 1.54%, due June 21, 2012 |
|
|
60.0 |
|
|
|
|
|
Total long-term debt (b) |
|
$ |
656.5 |
|
|
|
|
|
|
|
|
(a) |
|
$575.0 million of debt has been swapped to a fixed rate obligation with effective fixed
rates ranging from 2.26% to 5.19%, for a net effective rate of 4.48% on the $596.5 million
of outstanding debt under our revolving credit facility as of December 31, 2008. |
|
(b) |
|
The term loan facility is fully secured by restricted investments. |
19
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
Credit Agreement
We have an $824.6 million 5-year credit agreement that matures June 21, 2012, or the Credit
Agreement, which consists of:
|
|
|
a $764.6 million revolving credit facility; and |
|
|
|
|
a $60.0 million term loan facility. |
At December 31, 2008, we had $0.3 million of letters of credit outstanding. Outstanding
balances under the term loan facility are fully collateralized by investments in high-grade
securities, which are classified as restricted investments in the accompanying consolidated balance
sheet as of December 31, 2008. As of December 31, 2008, the available capacity under the revolving
credit facility was $171.5 million, which is net of approximately $21.7 million non-participation
by Lehman Brothers Commercial Bank, or Lehman Brothers, as discussed below. We have incurred $0.6
million of debt issuance costs associated with the Credit Agreement. These expenses are deferred as
other long-term assets in the consolidated balance sheet and will be amortized over the term of the
Credit Agreement.
Under the Credit Agreement, indebtedness under the revolving credit facility bears interest at
either: (1) the higher of Wachovia Banks prime rate or the Federal Funds rate plus 0.50%; or (2)
LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our leverage
level or credit rating. The revolving credit facility incurs an annual facility fee of 0.07% to
0.175% depending on our applicable leverage level or debt rating. This fee is paid on drawn and
undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate
equal to either: (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Banks prime rate or the
Federal Funds rate plus 0.50%.
The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated
indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not
more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters
(including the quarter in which such acquisition is consummated) following the consummation of
asset acquisitions in the midstream energy business of not more than 5.5 to 1.0. The Credit
Agreement also requires us to maintain an interest coverage ratio (the ratio of our consolidated
EBITDA to our consolidated interest expense, in each case as is defined by the Credit Agreement) of
equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter
period ending on the date of determination.
Lehman Brothers is a lender in our Credit Agreement. Lehman Brothers has not funded its
portion of our borrowing requests since its bankruptcy, and it is uncertain whether it will
participate in future borrowing requests. Accordingly, the availability of new borrowings under the
Credit Agreement has been reduced by approximately $25.4 million as of December 31, 2008. Our
borrowing capacity may be further limited by the Credit Agreements financial covenant
requirements. Except in the case of a default, amounts borrowed under our credit facility will not
mature prior to the June 21, 2012 maturity date.
Other Agreements
As of December 31, 2008, we had an outstanding letter of credit with a counterparty to our
commodity derivative instruments of $10.0 million, which reduces the amount of cash we may be
required to post as collateral. This letter of credit was issued directly by a financial
institution and does not reduce the available capacity under our credit facility.
12. Non-Controlling Interest
Non-controlling interest represents (1) the ownership interests of DCP Partners public
unitholders in net assets of DCP Partners through DCP Partners publicly traded common units; (2)
affiliate ownership interests in common units and in all of the subordinated units; (3) the
non-controlling interest holders portion of the net assets of our Collbran Valley Gas Gathering
system joint venture, acquired with the MEG acquisition in August 2007; and (4) the non-controlling
interest holders portion of the net assets of Jackson Pipeline Company, a partnership we acquired
with the MPP acquisition in October 2008.
We own approximately a 1% general partner interest in DCP Partners. For financial reporting
purposes, the assets and liabilities of DCP Partners are consolidated with those of our own, with
any third party and affiliate investors interest in our consolidated balance sheet amounts shown
as non-controlling interest. Distributions to and contributions from non-controlling interests
represent cash payments and cash contributions, respectively, from such third-party and affiliate
investors.
At December 31, 2008, DCP Partners had outstanding 24,661,754 common units and 3,571,429
subordinated units.
20
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
General DCP Partners partnership agreement requires that, within 45 days after the end of
each quarter, DCP Partners distribute all Available Cash (defined below) to unitholders of record
on the applicable record date, as determined by us as the general partner.
In January 2008, DCP Partners registration statement on Form S-3 to register the 3,005,780
common limited partner units represented in the June 2007 private placement agreement and the
2,380,952 common limited partner units represented in the August 2007 private placement agreement
was declared effective by the SEC.
In March 2008, DCP Partners issued 4,250,000 common limited partner units at $32.44 per unit,
and received proceeds of $132.1 million, net of offering costs.
Definition of Available Cash Available Cash, for any quarter, consists of all cash and cash
equivalents on hand at the end of that quarter:
|
|
|
less the amount of cash reserves established by us as the general partner to: |
|
|
|
provide for the proper conduct of our business; |
|
|
|
|
comply with applicable law, any of our debt instruments or other agreements;
or |
|
|
|
|
provide funds for distributions to the unitholders and to us as the general
partner for any one or more of the next four quarters; |
|
|
|
plus, if we, as the general partner so determine, all or a portion of cash and cash
equivalents on hand on the date of determination of Available Cash for the quarter. |
General Partner Interest and Incentive Distribution Rights Prior to June 2007, as the
general partner, we were entitled to 2% of all quarterly distributions that we make prior to DCP
Partners liquidation. We have the right, but not the obligation, to contribute a proportionate
amount of capital to maintain our current general partner interest. We did not participate in
certain issuances of common units by DCP Partners during 2007 and 2008. Therefore, our 2% interest
in these distributions was reduced to approximately 1%.
The incentive distribution rights held by us as the general partner entitle us to receive an
increasing share of Available Cash when pre-defined distribution targets are achieved. Currently,
our distribution related to our incentive distribution rights is at the highest level. Our
incentive distribution rights were not reduced as a result of these private placement agreements,
and will not be reduced if DCP Partners issues additional units in the future and we do not
contribute a proportionate amount of capital to DCP Partners to maintain our current general
partner interest. Please read the Distributions of Available Cash during the Subordination Period
and Distributions of Available Cash after the Subordination Period sections below for more details
about the distribution targets and their impact on our incentive distribution rights.
Subordinated Units All of the subordinated units are held by DCP Midstream, LLC. DCP
Partners partnership agreement provides that, during the subordination period, the common units
will have the right to receive distributions of Available Cash each quarter in an amount equal to
$0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of
the Minimum Quarterly Distribution on the common units from prior quarters, before any
distributions of Available Cash may be made on the subordinated units. These units are deemed
subordinated because for a period of time, referred to as the subordination period, the
subordinated units will not be entitled to receive any distributions until the common units have
received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore,
no arrearages will be paid on the subordinated units. The practical effect of the subordinated
units is to increase the likelihood that during the subordination period there will be Available
Cash to be distributed on the common units. The subordination period will end, and the subordinated
units will convert to common units, on a one for one basis, when certain distribution requirements,
as defined in the partnership agreement, have been met. The subordination period has an early
termination provision that permits 50% of the subordinated units to convert to common units on the
second business day following the first quarter distribution in 2008 and the other 50% of the
subordinated units to convert to common units on the second business day following the first
quarter distribution in 2009, provided the tests for ending the subordination period contained in
the partnership agreement are satisfied. DCP Partners determined that the criteria set forth in the
partnership agreement for early termination of the subordination period occurred in February 2008
and, therefore, 50% of the subordinated units, or 3,571,428 units, converted into common units. DCP
Partners determined that the criteria set forth in the partnership agreement for early termination
of the subordination period occurred in February 2009 and, therefore, the remaining 3,571,429
units, converted into common units. DCP Partners board of directors and the conflicts committee of
the board certified that all conditions for early conversion were satisfied. The rights of the
subordinated unitholders, other than the distribution rights described above, are substantially the
same as the rights of the common unitholders.
21
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
Distributions of Available Cash during the Subordination Period DCP Partners partnership
agreement, after adjustment for our relative ownership level, currently approximately 1%, requires
that DCP Partners make distributions of Available Cash for any quarter during the subordination
period in the following manner:
|
|
|
first, to the common unitholders and us as the general partner, in accordance with
their pro rata interest, until DCP Partners distributes for each outstanding common unit
an amount equal to the Minimum Quarterly Distribution for that quarter; |
|
|
|
|
second, to the common unitholders and us as the general partner, in accordance with
their pro rata interest, until DCP Partners distributes for each outstanding common unit
an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on
the common units for any prior quarters during the subordination period; |
|
|
|
|
third, to the subordinated unitholders and us as the general partner, in accordance
with their pro rata interest, until DCP Partners distributes for each subordinated unit
an amount equal to the Minimum Quarterly Distribution for that quarter; |
|
|
|
|
fourth, to all unitholders and us as the general partner, in accordance with their
pro rata interest, until each unitholder receives a total of $0.4025 per unit for that
quarter (the First Target Distribution); |
|
|
|
|
fifth, 13% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders pro rata until each unitholder receives a total of $0.4375
per unit for that quarter (the Second Target Distribution); |
|
|
|
|
sixth, 23% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders pro rata until each unitholder receives a total of $0.525
per unit for that quarter (the Third Target Distribution); and |
|
|
|
|
thereafter, 48% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders (the Fourth Target Distribution). |
Distributions of Available Cash after the Subordination Period DCP Partners partnership
agreement, after adjustment for our relative ownership level, requires that DCP Partners make
distributions of Available Cash from operating surplus for any quarter after the subordination
period in the following manner:
|
|
|
first, to all unitholders and us as the general partner, in accordance with their pro
rata interest, until each unitholder receives a total of $0.4025 per unit for that
quarter; |
|
|
|
|
second, 13% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders pro rata until each unitholder receives a total of $0.4375
per unit for that quarter; |
|
|
|
|
third, 23% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders pro rata until each unitholder receives a total of $0.525
per unit for that quarter; and |
|
|
|
|
thereafter, 48% to us as the general partner, plus our pro rata interest, and the
remainder to all unitholders. |
The following table presents DCP Partners cash distributions paid in 2008:
|
|
|
|
|
|
|
|
|
|
|
Per Unit |
|
Total Cash |
Payment Date |
|
Distribution |
|
Distribution |
|
|
|
|
|
|
(Millions) |
November 14, 2008 |
|
$ |
0.600 |
|
|
$ |
20.1 |
|
August 14, 2008 |
|
|
0.600 |
|
|
|
20.1 |
|
May 15, 2008 |
|
|
0.590 |
|
|
|
19.6 |
|
February 14, 2008 |
|
|
0.570 |
|
|
|
15.7 |
|
13. Partners Deficit
At December 31, 2008, partners deficit consisted of our capital account, AOCI and a note
receivable from DCP Midstream, LLC.
As of December 31, 2008, we had a deficit balance of $5.3 million in our partners deficit
account. This negative balance does not represent an asset to us and does not represent obligations
by us to contribute cash or other property. The partners deficit account generally consists of our
cumulative share of net income less cash distributions made plus capital contributions made. Cash
distributions that we receive during a period from DCP Partners may exceed our interest in DCP
Partners net income for the period. DCP Partners makes quarterly cash distributions of all of its
Available Cash, defined above. Future cash distributions that exceed net income and contributions
made will result in an increase in the deficit balance in the partners deficit account.
22
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
14. Risk Management Activities, Credit Risk and Financial Instruments
The impact of our derivative activity on our financial position is summarized below:
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
|
(Millions) |
Interest rate cash flow hedges: |
|
|
|
|
Net deferred losses in AOCI |
|
$ |
(0.5 |
) |
For the year ended December 31, 2008, no derivative gains or losses were reclassified from
AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to
certain forecasted transactions that are not probable of occurring.
We are exposed to market risks, including changes in commodity prices and interest rates. We
may use financial instruments such as forward contracts, swaps and futures to mitigate the effects
of the identified risks. In general, we attempt to mitigate risks related to the variability of
future cash flows resulting from changes in applicable commodity prices or interest rates so that
we can maintain cash flows sufficient to meet debt service, required capital expenditures,
distribution objectives and similar requirements. We have established a comprehensive risk
management policy, or the Risk Management Policy, and a risk management committee, to monitor and
manage market risks associated with commodity prices and interest rates. Our Risk Management Policy
prohibits the use of derivative instruments for speculative purposes.
As of December 31, 2008, we had an outstanding letter of credit with a counterparty to our
commodity derivative instruments of $10.0 million. This letter of credit reduces the amount of cash
we may be required to post as collateral. As of December 31, 2008, we had no cash collateral posted
with counterparties to our commodity derivative instruments.
Commodity Price Risk Our operations of gathering, processing, and transporting natural gas,
and the accompanying operations of transporting and marketing of NGLs create commodity price risk
due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs,
natural gas and crude oil. As an owner and operator of natural gas processing and other midstream
assets, we have an inherent exposure to market variables and commodity price risk. The amount and
type of price risk is dependent on the underlying natural gas contracts to purchase and process
natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs,
and related products produced, processed, transported or stored.
Our wholesale propane logistics business is generally designed to establish stable margins by
entering into supply arrangements that specify prices based on established floating price indices
and by entering into sales agreements that provide for floating prices that are tied to our
variable supply costs plus a margin. To the extent that we carry propane inventories or our sales
and supply arrangements are not aligned, we are exposed to market variables and commodity price
risk. The amount and type of price risk is dependent on the mechanisms and locations for purchases,
sales, transportation and storage of propane.
We manage our commodity derivative activities in accordance with our Risk Management Policy,
which limits exposure to market risk and requires regular reporting to management of potential
financial exposure.
Interest Rate Risk Interest rates on credit facility balances and debt offerings could be
higher than current levels, causing our financing costs to increase accordingly. Although this
could limit our ability to raise funds in the debt capital markets, we expect to remain competitive
with respect to acquisitions and capital projects, as our competitors would face similar
circumstances.
Credit Risk In the Natural Gas Services segment, we sell natural gas to marketing affiliates
of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of
DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants.
In the Wholesale Propane Logistics segment, we sell primarily to retail propane distributors. In
the NGL Logistics segment, our principal customers include an affiliate of DCP Midstream, LLC,
producers and marketing companies. Concentration of credit risk may affect our overall credit risk,
in that these customers may be similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, we analyze the counterparties financial condition prior to
entering into an agreement, establish credit limits, and monitor the appropriateness of these
limits on an ongoing basis. We operate under DCP Midstream, LLCs corporate credit policy. DCP
Midstream, LLCs corporate credit policy, as well as the standard terms and conditions of our
agreements, prescribe the use of financial responsibility and reasonable grounds for adequate
assurances. These provisions allow our credit department to request that a counterparty remedy
credit limit violations by posting cash or letters of credit
23
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
for exposure in excess of an established credit line. The credit line represents an open
credit limit, determined in accordance with DCP Midstream, LLCs credit policy and guidelines. The
agreements also provide that the inability of a counterparty to post collateral is sufficient cause
to terminate a contract and liquidate all positions. The adequate assurance provisions also allow
us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer
provides security for payment to us in a satisfactory form.
Commodity Cash Flow Protection Activities We used NGL, natural gas and crude oil swaps to
mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. Prior to
July 1, 2007, the effective portion of the change in fair value of a derivative designated as a
cash flow hedge was accumulated in AOCI. During the period in which the hedged transaction impacted
earnings, amounts in AOCI associated with the hedged transaction were reclassified to earnings in
the same accounts as the item being hedged. The impact of our derivative activity on our
consolidated financial position as of December 31, 2008 is insignificant.
Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our
commodity cash flow hedges. Therefore, we are using the mark-to-market method of accounting for all
commodity derivative instruments. As a result, an insignificant amount of the remaining net loss deferred in
AOCI at December 31, 2008 is expected to be reclassified to earnings, through December 2011, as the
underlying transactions impact earnings. Subsequent to July 1, 2007, the changes in fair value of
financial derivatives are included in earnings. The agreements are with major financial
institutions, which management expects to fully perform under the terms of the agreements.
As of December 31, 2008, we have mitigated the majority of our expected natural gas, NGL and
condensate commodity price risk associated with the equity volumes from our gathering and
processing operations through 2013 with natural gas, NGLs and crude oil derivatives.
Other Asset-Based Activity To the extent possible, we match the pricing of our supply
portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price
risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both
physical and financial transactions. We occasionally will enter into financial derivatives to lock
in price variability across the Pelico system to maximize the value of pipeline capacity. These
financial derivatives are accounted for using mark-to-market accounting with changes in fair value
recognized in current period earnings.
Our wholesale propane logistics business is generally designed to establish stable margins by
entering into supply arrangements that specify prices based on established floating price indices
and by entering into sales agreements that provide for floating prices that are tied to our
variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements
in the event that a retail propane distributor desires to purchase propane from us on a fixed price
basis. We manage this risk with both physical and financial transactions, sometimes using
non-trading derivative instruments, which generally allow us to swap our fixed price risk to market
index prices that are matched to our market index supply costs. In addition, we may on occasion use
financial derivatives to manage the value of our propane inventories. These financial derivatives
are accounted for using mark-to-market accounting with changes in fair value recognized in current
period earnings.
Commodity Fair Value Hedges Historically, we used fair value hedges to mitigate risk to
changes in the fair value of an asset or a liability (or an identified portion thereof) that is
attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) to
reduce our cash flow exposure to fixed price risk by swapping the fixed price risk for a floating
price position (New York Mercantile Exchange or index-based).
Normal Purchases and Normal Sales If a contract qualifies and is designated as a normal
purchase or normal sale, no recognition of the contracts fair value in the consolidated balance
sheet is required until the associated delivery period impacts earnings. We have applied this
accounting election for contracts involving the purchase or sale of commodities in future periods
as well as select operating expense contracts.
Interest Rate Cash Flow Hedges We mitigate a portion of our interest rate risk with interest
rate swaps, which reduce our exposure to market rate fluctuations by converting variable interest
rates to fixed interest rates. These interest rate swap agreements convert the interest rate
associated with an aggregate of $575.0 million of the indebtedness outstanding under our revolving
credit facility to a fixed rate obligation, thereby reducing the exposure to market rate
fluctuations. All interest rate swap agreements have been designated as cash flow hedges, and
effectiveness is determined by matching the principal balance and terms with that of the specified
obligation. The effective portions of changes in fair value are recognized in AOCI in the
consolidated balance sheet. As a result, $0.2 million of the remaining net loss deferred
in AOCI at December 31, 2008 is expected to be reclassified into earnings during the next 12 months
as the hedged transactions impact earnings. However, due to the volatility of the interest rate
markets, the corresponding value in AOCI is subject to change prior to its reclassification into
earnings. Ineffective portions of
24
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
changes in fair value are recognized in earnings. $425.0 million of the agreements reprice
prospectively approximately every 90 days and the remaining $150.0 million of the agreements
reprice prospectively approximately every 30 days. Under the terms of the interest rate swap
agreements, we pay fixed rates ranging from 2.26% to 5.19%, and receive interest payments based on
the three-month LIBOR. The differences to be paid or received under the interest rate swap
agreements are recognized as an adjustment to interest expense. The agreements are with major
financial institutions, which are expected to fully perform under the terms of the agreements.
15. Equity-Based Compensation
On November 28, 2005, the board of directors of the General Partner adopted a long-term
incentive plan, or LTIP, for employees, consultants and directors of the General Partner and its
affiliates who perform services for us, effective as of December 7, 2005. Under the LTIP,
equity-based instruments may be granted to our key employees. The LTIP provides for the grant of
limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with
respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs.
Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to
awards under the LTIP. Awards that are canceled or forfeited, or are withheld to satisfy the
General Partners tax withholding obligations, are available for delivery pursuant to other awards.
The LTIP is administered by the compensation committee of the General Partners board of directors.
All awards are subject to cliff vesting, with the exception of the Phantom Units issued to
directors in conjunction with our initial public offering, which are subject to graded vesting
provisions.
All awards are accounted for as liability awards.
Performance Units We have awarded phantom LPUs, or Performance Units, pursuant to the LTIP
to certain employees. Performance Units generally vest in their entirety at the end of a three year
performance period. The number of Performance Units that will ultimately vest range from 0% to 200%
of the outstanding Performance Units, depending on the achievement of specified performance targets
over three year performance periods. The final performance payout is determined by the compensation
committee of the board of directors of the General Partner. The DERs will be paid in cash at the
end of the performance period. Of the remaining Performance Units outstanding at December 31, 2008,
21,705 units vested in January 2009, 15,101 units are expected to vest on December
31, 2009, and 8,544 units are expected to vest on December 31, 2010.
At December 31, 2008, there was approximately $0.3 million of unrecognized compensation
expense related to the Performance Units that is expected to be recognized over a weighted-average
period of 0.7 years. The following table presents information related to the Performance Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
Weighted- |
|
Measurement |
|
|
|
|
|
|
Average Price |
|
Date Price |
|
|
Units |
|
per Unit |
|
per Unit |
Outstanding at January 1, 2008 |
|
|
46,960 |
|
|
$ |
32.93 |
|
|
|
|
|
Granted |
|
|
17,085 |
|
|
$ |
33.85 |
|
|
|
|
|
Forfeited |
|
|
(12,025 |
) |
|
$ |
32.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
52,020 |
|
|
$ |
33.35 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest (a) |
|
|
45,350 |
|
|
$ |
31.70 |
|
|
$ |
9.40 |
|
|
|
|
(a) |
|
Based on our December 31, 2008 estimated achievement of specified
performance targets, the performance target for units granted in 2008 is 100%, for
units granted in 2007 is 102%, and for units granted in 2006 is 140.4%. The
estimated forfeiture rate for units granted in 2008 and 2007 is 50%, and for units
granted in 2006 is 0%. |
The estimate of Performance Units that are expected to vest is based on highly subjective
assumptions that could potentially change over time, including the expected forfeiture rate and
achievement of performance targets. Therefore, the amount of unrecognized compensation expense
noted above does not necessarily represent the value that will ultimately be realized in earnings.
Phantom Units In conjunction with our initial public offering, in January 2006 the General
Partners board of directors awarded phantom LPUs, or Phantom Units, to key employees, and to
directors who are not officers or employees of affiliates of the General Partner. The remaining
Phantom Units outstanding at December 31, 2008 vested on January 3, 2009.
In 2007, we granted 4,500 Phantom Units, pursuant to the LTIP, to directors who are not
officers or employees of affiliates of the General Partner as part of their annual director fees
for 2007. Of these units, 4,000 units vested during 2007 and 500 units vested in February 2008.
25
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
In 2008, we granted 4,000 Phantom Units, pursuant to the LTIP, to directors who are not
officers or employees of affiliates of the General Partner as part of their annual director fees
for 2008. All of these units vested during 2008.
The DERs are paid quarterly in arrears.
The following table presents information related to the Phantom Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
Weighted- |
|
Measurement |
|
|
|
|
|
|
Average Price |
|
Date Price |
|
|
Units |
|
per Unit |
|
per Unit |
Outstanding at January 1, 2008 |
|
|
20,199 |
|
|
$ |
24.56 |
|
|
|
|
|
Granted |
|
|
4,000 |
|
|
$ |
35.88 |
|
|
|
|
|
Forfeited |
|
|
(4,000 |
) |
|
$ |
24.05 |
|
|
|
|
|
Vested |
|
|
(6,501 |
) |
|
$ |
32.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
13,698 |
|
|
$ |
24.05 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
13,698 |
|
|
$ |
24.05 |
|
|
$ |
9.40 |
|
The estimate of Phantom Units that are expected to vest is based on highly subjective
assumptions that could potentially change over time, including the expected forfeiture rate.
Restricted Phantom Units Our General Partners board of directors awarded restricted phantom
LPUs, or RPUs, to key employees under the LTIP. The RPUs outstanding at December 31, 2008 are
expected to vest on December 31, 2011. The DERs are paid quarterly in arrears.
At December 31, 2008, there was approximately $0.2 million of unrecognized compensation
expense related to the RPUs that is expected to be recognized over a weighted-average period of 2.0
years. The following table presents information related to the RPUs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
Average |
|
Measurement |
|
|
|
|
|
|
Price |
|
Date Price |
|
|
Units |
|
per Unit |
|
per Unit |
Outstanding at January 1, 2008 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
Granted |
|
|
17,085 |
|
|
$ |
33.85 |
|
|
|
|
|
Forfeited |
|
|
(2,395 |
) |
|
$ |
35.88 |
|
|
|
|
|
Vested |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
14,690 |
|
|
$ |
33.52 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
8,544 |
|
|
$ |
33.85 |
|
|
$ |
9.40 |
|
The estimate of RPUs that are expected to vest is based on highly subjective assumptions that
could potentially change over time, including the expected forfeiture rate, which was estimated at
50% as of December 31, 2008. Therefore, the amount of unrecognized compensation expense noted above
does not necessarily represent the value that will ultimately be realized in earnings.
We intend to settle certain awards issued under the LTIP in cash upon vesting. Compensation
expense on these awards is recognized ratably over each vesting period, and will be remeasured each
reporting period for all awards outstanding until the units are vested. The fair value of all
awards is determined based on the closing price of DCP Partners common units at each measurement
date.
16. Income Taxes
We are structured as a master limited partnership, which is a pass-through entity for federal
income tax purposes. Accordingly, we had no deferred tax balances as of December 31, 2008.
26
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned
to Texas. During 2008 we acquired properties in Michigan. Michigan imposes a business tax of 0.8%
on gross receipts, and 4.95% of Michigan taxable income. The sum of the gross receipts and income
tax is subject to a tax surcharge of 21.99%. Michigan provides tax credits that may reduce our
final tax liability.
17. Commitments and Contingent Liabilities
Litigation
Driver In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP
Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County,
Texas. The litigation stems from an ongoing commercial dispute involving the construction of our
Wilbreeze pipeline, which was completed in December 2006. Driver was the primary contractor for
construction of the pipeline and the construction process was managed for us by DCP Midstream,
LP. Driver claims damages in the amount of $2.4 million for breach of contract. We believe Drivers
position in this litigation is without merit and we intend to vigorously defend ourselves against
this claim. It is not possible to predict whether we will incur any liability or to estimate the
damages, if any, we might incur in connection with this matter. Management does not believe the
ultimate resolution of this issue will have a material adverse effect on our consolidated results
of operations, financial position or cash flows.
El Paso On February 27, 2009, a jury in the District Count, Harris County, Texas rendered a
verdict in favor of El Paso E&P Company, L.P. and against one of our subsidiaries and DCP
Midstream. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing
commercial dispute involving our Minden processing plant that dates back to August 2000, which
includes periods of time prior to our ownership of this asset. Our responsibility for this judgment
will be limited to the time period after we acquired the asset from DCP Midstream in December 2005.
We intend to appeal this decision and will continue to defend ourselves vigorously against this
claim. Nevertheless, as a result of the jury verdict we have reserved a contingent liability of
$2.5 million for this matter, which is included in our consolidated balance sheet for the year
ended December 31, 2008.
Other We are not a party to any other significant legal proceedings, but are a party to
various administrative and regulatory proceedings and commercial disputes that have arisen in the
ordinary course of our business. Management currently believes that the ultimate resolution of the
foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage
or other indemnification arrangements, will not have a material adverse effect on our consolidated
financial position.
Insurance We contract with a third party insurer for our primary general liability insurance
covering third party exposures. DCP Midstream, LLC provides our remaining insurance coverage
through third party insurers for: (1) statutory workers compensation insurance; (2) automobile
liability insurance for all owned, non-owned and hired vehicles; (3) excess liability insurance
above the established primary limits for general liability and automobile liability insurance; and
(4) property insurance, which covers replacement value of all real and personal property and
includes business interruption/ extra expense and (5) directors and officers insurance covering our
directors and officers for acts related to our business activities. All coverage is subject to
certain limits and deductibles, the terms and conditions of which are common for companies with
similar types of operations.
Environmental The operation of pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs and other products is subject to
stringent and complex laws and regulations pertaining to health, safety and the environment. As an
owner or operator of these facilities, we must comply with United States laws and regulations at
the federal, state and local levels that relate to air and water quality, hazardous and solid waste
management and disposal, and other environmental matters. The cost of planning, designing,
constructing and operating pipelines, plants, and other facilities must incorporate compliance with
environmental laws and regulations and safety standards. Failure to comply with these laws and
regulations may trigger a variety of administrative, civil and potentially criminal enforcement
measures, including citizen suits, which can include the assessment of monetary penalties, the
imposition of remedial requirements, and the issuance of injunctions or restrictions on operation.
Management believes that, based on currently known information, compliance with these laws and
regulations will not have a material adverse effect on our consolidated results of operations,
financial position or cash flows.
Indemnification DCP Midstream, LLC has indemnified us for certain potential environmental
claims, losses and expenses associated with the operation of the assets of certain of our
predecessors. See the Indemnification section of Note 5 for additional details.
Other Commitments and Contingencies We utilize assets under operating leases in several
areas of operation.
Minimum rental payments under our various operating leases in the year indicated are as
follows at December 31, 2008:
27
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
|
|
|
|
|
|
|
(Millions) |
|
2009 |
|
$ |
12.4 |
|
2010 |
|
|
9.0 |
|
2011 |
|
|
7.9 |
|
2012 |
|
|
7.0 |
|
2013 |
|
|
5.8 |
|
Thereafter |
|
|
2.6 |
|
|
|
|
|
Total minimum rental payments |
|
$ |
44.7 |
|
|
|
|
|
18. Business Segments
Our operations are located in the United States and are organized into three reporting
segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.
Natural Gas Services The Natural Gas Services segment consists of (1) the Northern Louisiana
system; (2) the Southern Oklahoma system that was acquired in May 2007; (3) our 25% limited
liability company interest in East Texas, our 40% limited liability company interest in Discovery,
and the losses associated with the Swap acquired in July 2007; and (4) our Colorado and Wyoming
systems, acquired in August 2007; and (5) our Michigan system, acquired in October 2008.
Wholesale Propane Logistics The Wholesale Propane Logistics segment consists of six owned
rail terminals, one of which idled in 2007 to consolidate our operations, one leased marine
terminal, one pipeline terminal and access to several open access pipeline terminals.
NGL Logistics The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL
transportation pipelines, and a non-operated 45% equity interest in the Black Lake interstate NGL
pipeline. DCP Midstream, LLC owns a 5% interest in Black Lake and an affiliate of BP PLC owns the
remaining interest and is the operator of Black Lake. The Wilbreeze transportation pipeline began
operations in December 2006.
These segments are monitored separately by management for performance against our internal
forecast and are consistent with internal financial reporting. These segments have been identified
based on the differing products and services, regulatory environment and the expertise required for
these operations.
The following table sets forth our segment information:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(Millions) |
|
Segment long-term assets: |
|
|
|
|
Natural Gas Services (a) |
|
$ |
856.4 |
|
Wholesale Propane Logistics |
|
|
54.3 |
|
NGL Logistics |
|
|
33.8 |
|
Other (b) |
|
|
70.3 |
|
|
|
|
|
Total long-term assets |
|
|
1,014.8 |
|
Current assets |
|
|
165.2 |
|
|
|
|
|
Total assets |
|
$ |
1,180.0 |
|
|
|
|
|
|
|
|
(a) |
|
Long-term assets for our Natural Gas Services segment increased in
2008 as a result of our Michigan acquisition in October 2008. |
|
(b) |
|
Other long-term assets not allocable to segments consist of restricted
investments, unrealized gains on derivative instruments, and other
long-term assets. |
28
DCP MIDSTREAM GP, LP
NOTES TO CONSOLIDATED BALANCE SHEET (Continued)
AS OF DECEMBER 31, 2008
19. Subsequent Events
On February 27, 2009, a jury in the District Count, Harris County, Texas rendered a verdict in
favor of El Paso E&P Company, L.P. and against one of DCP Partners subsidiaries and DCP Midstream.
As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial
dispute involving our Minden processing plant that dates back to August 2000, which includes
periods of time prior to our ownership of this asset. Our responsibility for this judgment will be
limited to the time period after DCP Partners acquired the asset from DCP Midstream in December
2005. DCP Partners intend to appeal this decision and will continue to defend vigorously against
this claim. Nevertheless, as a result of the jury verdict we have reserved a contingent liability
of $2.5 million for this matter, which is included in our consolidated balance sheet for the year
ended December 31, 2008.
On February 25, 2009, DCP Partners entered into a Contribution Agreement with DCP Midstream,
LLC, whereby DCP Midstream, LLC will contribute an additional 25.1% interest in East Texas to DCP
Partners in exchange for 3.5 million Class D units, providing DCP Partners with a 50.1% interest in
East Texas following the expected closing of the transaction in April 2009. This closing date is
subject to extension for up to 45 days to allow for repairs or replacement to DCP Partners
reasonable satisfaction any assets destroyed or damaged by certain casualty losses and time to enable the plant to process all available inlet volumes as defined in
the Contribution Agreement. The Class D units will automatically convert into common units in
August 2009 and will not be eligible to receive a distribution until the second quarter
distribution payable in August 2009. DCP Midstream, LLC has agreed to provide a fixed-price NGL
derivative by NGL component for the period of April 2009 to March 2010 for the acquired interest.
Subsequent to this transaction, we will consolidate East Texas in our consolidated balance sheet.
On February 11, 2009, DCP Partners announced, along with DCP Midstream, LLC, that our East
Texas natural gas processing complex and residue natural gas delivery system known as the Carthage
Hub, have been temporarily shut in following a fire that was caused by a third party underground
pipeline outside of our property line that ruptured. No employees or contractors were injured in
the incident. There was no significant damage to the natural gas processing complex. As of February
25, 2009, the complex began processing through one of the five plants, and it is expected that full
processing capacities will be restored for the entire complex over the next 30 days. Residue gas
will be redelivered into limited available pipeline interconnects while the Carthage Hub undergoes
inspection and repairs.
On February 17, 2009, the remaining 3,571,429 DCP Partners subordinated units were converted
to common units following the completion of the subordination period and satisfactory completion of
all subordination period tests contained in the DCP Partners partnership agreement.
In February 2009, DCP Partners entered into interest rate swap agreements to convert $275.0
million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby
reducing the exposure to interest rate fluctuations. These interest rate swaps commence in December
2010 and expire in June 2012
On January 27, 2009, the board of directors of the General Partner declared a quarterly
distribution of $0.60 per unit, payable on February 13, 2009 to unitholders of record on February
6, 2009.
29
exv99w2
Exhibit 99.2
DCP Midstream, LLC
Consolidated Balance Sheet
As of December 31, 2008
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Deloitte & Touche LLP |
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Suite 3600 |
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555 Seventeenth Street |
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Denver, CO 80202-3942 |
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USA |
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Tel: +1 303 292 5400 |
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Fax: +1 303 312 4000 |
|
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www.deloitte.com |
INDEPENDENT AUDITORS REPORT
To the Board of Directors and Members of
DCP Midstream, LLC
Denver, Colorado
We have audited the accompanying consolidated balance sheet of DCP Midstream, LLC and subsidiaries
(the Company) as of December 31, 2008. This financial statement is the responsibility of the
Companys management. Our responsibility is to express an opinion on this financial statement based
on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United
States of America. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An audit includes
consideration of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated balance sheet presents fairly, in all material respects, the
financial position of the Company as of December 31, 2008 in conformity with accounting principles
generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 18, 2009
DCP MIDSTREAM, LLC
CONSOLIDATED BALANCE SHEET
(millions)
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
ASSETS |
|
|
|
|
Current assets: |
|
|
|
|
Cash and cash equivalents |
|
$ |
133 |
|
Accounts receivable: |
|
|
|
|
Customers, net of allowance for doubtful accounts of
$6 million |
|
|
735 |
|
Affiliates |
|
|
221 |
|
Other |
|
|
44 |
|
Inventories |
|
|
43 |
|
Unrealized gains on derivative instruments |
|
|
419 |
|
Other |
|
|
70 |
|
|
|
|
|
Total current assets |
|
|
1,665 |
|
|
|
|
|
Property, plant and equipment, net |
|
|
4,836 |
|
Restricted investments |
|
|
60 |
|
Investments in unconsolidated affiliates |
|
|
179 |
|
Intangible assets, net |
|
|
319 |
|
Goodwill |
|
|
565 |
|
Unrealized gains on derivative instruments |
|
|
119 |
|
Other long-term assets |
|
|
49 |
|
|
|
|
|
Total assets |
|
$ |
7,792 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY |
|
|
|
|
Current liabilities: |
|
|
|
|
Accounts payable: |
|
|
|
|
Trade |
|
$ |
888 |
|
Affiliates |
|
|
48 |
|
Other |
|
|
46 |
|
Short-term borrowings |
|
|
100 |
|
Unrealized losses on derivative instruments |
|
|
398 |
|
Accrued interest payable |
|
|
59 |
|
Accrued taxes |
|
|
44 |
|
Other |
|
|
188 |
|
|
|
|
|
Total current liabilities |
|
|
1,771 |
|
|
|
|
|
Long-term debt |
|
|
3,602 |
|
Unrealized losses on derivative instruments |
|
|
81 |
|
Other long-term liabilities |
|
|
376 |
|
Non-controlling interest |
|
|
312 |
|
Commitments and contingent liabilities |
|
|
|
|
Members equity: |
|
|
|
|
Members interest |
|
|
1,667 |
|
Accumulated other comprehensive loss |
|
|
(17 |
) |
|
|
|
|
Total members equity |
|
|
1,650 |
|
|
|
|
|
Total liabilities and members equity |
|
$ |
7,792 |
|
|
|
|
|
See Notes to Consolidated Balance Sheet
2
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2008
1. General and Summary of Significant Accounting Policies
Basis of Presentation DCP Midstream, LLC, with its consolidated subsidiaries, us, we, our,
or the Company, is a joint venture owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by
ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of
gathering, processing, compressing, transporting and storing of natural gas, and fractionating,
transporting, gathering, treating, processing and storing of natural gas liquids, or NGLs, as well
as marketing, from which we generate revenues primarily by trading and marketing natural gas and
NGLs.
DCP Midstream Partners, LP, or DCP Partners, is a master limited partnership, of which our
subsidiary, DCP Midstream GP, LP, acts as general partner. As of December 31, 2008, we owned an
approximately 29% limited partnership interest, and an approximately 1% general partnership
interest in DCP Partners, as well as incentive distribution rights that entitle us to receive an
increasing share of available cash as pre-defined distribution targets are achieved. As the general
partner of DCP Partners, we have responsibility for its operations. Since we exercise control over
DCP Partners, we account for them as a consolidated subsidiary.
We are governed by a five member board of directors, consisting of two voting members from
each parent and our Chief Executive Officer and President, a non-voting member. All decisions
requiring board of directors approval are made by simple majority vote of the board, but must
include at least one vote from both a Spectra Energy and ConocoPhillips board member. In the event
the board cannot reach a majority decision, the decision is appealed to the Chief Executive
Officers of both Spectra Energy and ConocoPhillips.
The consolidated financial statement includes the accounts of the Company and all
majority-owned subsidiaries where we have the ability to exercise control, variable interest
entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We
also consolidate DCP Partners, which we control as the general partner and where the limited
partners do not have substantive kick-out or participating rights. Investments in greater than 20%
owned affiliates that are not variable interest entities and where we do not have the ability to
exercise control, and investments in less than 20% owned affiliates where we have the ability to
exercise significant influence, are accounted for using the equity method. Intercompany balances
and transactions have been eliminated.
Use of Estimates Conformity with accounting principles generally accepted in the United
States of America, or GAAP, requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statement and notes. Although these estimates are
based on managements best available knowledge of current and expected future events, actual
results could be different from these estimates.
Cash and Cash Equivalents Cash and cash equivalents include all cash balances and highly
liquid investments with an original maturity of three months or less.
Short-Term and Restricted Investments We may invest available cash balances in various
financial instruments, such as commercial paper, money market instruments and tax-exempt debt
securities that have stated maturities of 20 years or more. These instruments provide for a high
degree of liquidity through features, which allow for the redemption of the investment at its face
amount plus earned income. As we generally intend to sell these instruments within one year or less
from the balance sheet date, and as they are available for use in current operations, they are
classified as current assets, unless otherwise restricted. We have classified all short-term and
restricted debt investments as available-for-sale and they are carried at fair market value.
Unrealized gains and losses on available-for-sale securities are recorded in the consolidated
balance sheet as accumulated other comprehensive income or loss, or AOCI. No such gains or losses
were deferred in AOCI at December 31, 2008. Restricted investments consist of collateral for DCP
Partners term loan. The costs, including accrued interest on investments, approximates fair value
due to the short-term, highly liquid nature of the securities held by us and as interest rates are
re-set on a daily, weekly or monthly basis.
Inventories Inventories consist primarily of natural gas and NGLs held in storage for
transportation and processing and sales commitments. Inventories are valued at the lower of
weighted average cost or market. Transportation costs are included in inventory on the consolidated
balance sheet.
3
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Accounting for Risk Management and Derivative Activities and Financial Instruments Effective
July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives
associated with managing DCP Partners commodity price risk. We have used the mark-to-market method
of accounting for all commodity derivative instruments associated with managing DCP Partners
commodity price risk since July 2007. As a result, the remaining net loss deferred in AOCI is being
reclassified to sales of natural gas and petroleum products through December 2011, as the
underlying transactions impact earnings.
Each derivative not qualifying for the normal purchases and normal sales exception is recorded
on a gross basis in the consolidated balance sheet at its fair value as unrealized gains or
unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities
remain classified in the consolidated balance sheet as unrealized gains or unrealized losses on
mark-to-market and hedging instruments at fair value until the contractual delivery period impacts
earnings.
We designate each energy commodity derivative as either trading or non-trading. Certain
non-trading derivatives are further designated as either a hedge of a forecasted transaction or
future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment
(fair value hedge), or a normal purchase or normal sale contract. The remaining non-trading
derivatives (which are related to asset based activity) for which hedge accounting or the normal
purchase or normal sale exception are not elected, are recorded at fair value on the balance sheet,
under the following accounting methods:
|
|
|
Classification of Contract |
|
Accounting Method |
Trading Derivatives |
|
Mark-to-market method b |
Non-Trading Derivatives: |
|
|
Cash Flow Hedge a |
|
Hedge method c |
Fair Value Hedge |
|
Hedge method c |
Normal Purchase or
Normal Sale |
|
Accrual method d |
Non-Trading Derivatives |
|
Mark-to-market method b |
|
|
|
a |
|
Effective July 1, 2007, all commodity cash flow hedges relating to derivatives
associated with managing DCP Partners commodity price risk are classified as non-trading
derivative activity. Our other commodity cash flow hedges and our interest rate swaps continue to
be accounted for as cash flow hedges. |
|
b |
|
Mark-to-marketAn accounting method whereby the change in the fair value of the asset
or liability is recognized in the consolidated statements of operations and comprehensive income in
trading and marketing gains and losses during the current period. |
|
c |
|
Hedge methodAn accounting method whereby the change in the fair value of the asset or
liability is recorded in the consolidated balance sheet as unrealized gains or unrealized losses on
mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the
consolidated statements of operations and comprehensive income for the effective portion until the
service is provided or the associated delivery period impacts earnings. For fair value hedges, the
changes in the fair value of the asset or liability, as well as the offsetting changes in value of
the hedged item, are recognized in the consolidated statements of operations and comprehensive
income in the same category as the related hedged item. |
|
d |
|
Accrual methodAn accounting method whereby there is no recognition in the
consolidated balance sheet or consolidated statements of operations and comprehensive income for
changes in fair value of a contract until the service is provided or the associated delivery period
impacts earnings. |
Cash Flow and Fair Value Hedges For derivatives designated as a cash flow hedge or a fair
value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at
the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective
in offsetting changes in cash flows or fair values of hedged items. All components of each
derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise
noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated
balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging instruments.
The effective portion of the change in fair value of a derivative designated as a cash flow hedge
is recorded in the consolidated balance sheet as AOCI. During the period in which the hedged
transaction impacts earnings, amounts in AOCI associated with the hedged transaction are
reclassified to the consolidated statement of operations and comprehensive income in the same
accounts as the item being hedged. We discontinue hedge accounting prospectively when it is
determined that the derivative no longer qualifies as an effective hedge, or when it is probable
that the hedged transaction will not occur. When hedge accounting is discontinued because the
derivative no longer qualifies as an effective hedge, the derivative is subject to the
mark-to-market accounting method prospectively. The derivative continues to be carried on the
consolidated balance
4
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
sheet at its fair value; however, subsequent changes in its fair value are recognized in
current period earnings. Gains and losses related to discontinued hedges that were previously
accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is
probable that the hedged transaction will not occur, in which case, the gains and losses that were
previously deferred in AOCI will be immediately recognized in current period earnings.
For derivatives designated as fair value hedges, we recognize the gain or loss on the
derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in
the current period. All derivatives designated and accounted for as fair value hedges are
classified in the same category as the item being hedged in the consolidated statements of
operations and comprehensive income.
Valuation When available, quoted market prices or prices obtained through external sources
are used to determine a contracts fair value. For contracts with a delivery location or duration
for which quoted market prices are not available, fair value is determined based on internally
developed pricing models developed primarily from historical and expected correlations with quoted
market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the
potential impact of liquidating open positions in an orderly manner over a reasonable time period
under current conditions. Changes in market prices and management estimates directly affect the
estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates
may change in the near term.
Property, Plant and Equipment Property, plant and equipment are recorded at original cost.
The cost of maintenance and repairs, which are not significant improvements, are expensed when
incurred. Depreciation is computed using the straight-line method over the estimated useful lives
of the assets.
Asset retirement obligations associated with tangible long-lived assets are recorded at fair
value in the period in which they are incurred, if a reasonable estimate of fair value can be made,
and added to the carrying amount of the associated asset. This additional carrying amount is then
depreciated over the life of the asset. The liability increases due to the passage of time based on
the time value of money until the obligation is settled. We recognize a liability for conditional
asset retirement obligations as soon as the fair value of the liability can be reasonably
estimated. A conditional asset retirement obligation is defined as an unconditional legal
obligation to perform an asset retirement activity in which the timing and/or method of settlement
are conditional on a future event that may or may not be within the control of the entity.
Investments in Unconsolidated Affiliates We use the equity method to account for investments
in greater than 20% owned affiliates that are not variable interest entities and where we do not
have the ability to exercise control, and investments in less than 20% owned affiliates where we
have the ability to exercise significant influence.
We evaluate our investments in unconsolidated affiliates for impairment when events or changes
in circumstances indicate, in managements judgment, that the carrying value of such investments
may have experienced an other than temporary decline in value. When evidence of loss in value has
occurred, management compares the estimated fair value of the investment to the carrying value of
the investment to determine whether any impairment has occurred. Management assesses the fair value
of our unconsolidated affiliates using commonly accepted techniques, and may use more than one
method, including, but not limited to, recent third party comparable sales and discounted cash flow
models. If the estimated fair value is less than the carrying value and management considers the
decline in value to be other than temporary, the excess of the carrying value over the estimated
fair value is recognized in the financial statements as an impairment loss.
Intangible Assets and Goodwill Intangible assets consist primarily of customer contracts and
related relationships, including commodity purchase, transportation and processing contracts. These
intangible assets are amortized on a straight-line basis over the term of the contract or
anticipated relationship, ranging from less than one to 25 years. Goodwill is the cost of an
acquisition less the fair value of the net assets of the acquired business.
We evaluate goodwill for impairment annually in the third quarter, and whenever events or
changes in circumstances indicate it is more likely than not that the fair value of a reporting
unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step
process. The first step involves comparing the fair value of the reporting unit, to which goodwill
has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds
its fair value, the second step of the process involves comparing
5
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
the fair value and carrying value of the goodwill of that reporting unit. If the carrying
value of the goodwill of a reporting unit exceeds the fair value of that goodwill, the excess of
the carrying value over the fair value is recognized as an impairment loss.
Long-Lived Assets We evaluate whether the carrying value of long-lived assets, excluding
goodwill, has been impaired when circumstances indicate the carrying value of those assets may not
be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash
flows expected to result from the use and eventual disposition of the asset. We consider various
factors when determining if these assets should be evaluated for impairment, including but not
limited to:
|
|
|
a significant adverse change in legal factors or business climate; |
|
|
|
|
a current period operating or cash flow loss combined with a history of operating or
cash flow losses, or a projection or forecast that demonstrates continuing losses
associated with the use of a long-lived asset; |
|
|
|
|
an accumulation of costs significantly in excess of the amount originally expected for
the acquisition or construction of a long-lived asset; |
|
|
|
|
significant adverse changes in the extent or manner in which an asset is used, or in its
physical condition; |
|
|
|
|
a significant adverse change in the market value of an asset; and |
|
|
|
|
a current expectation that, more likely than not, an asset will be sold or otherwise
disposed of before the end of its estimated useful life. |
If the carrying value is not recoverable, the impairment loss is measured as the excess of the
assets carrying value over its fair value. Management assesses the fair value of long-lived assets
using commonly accepted techniques, and may use more than one method, including, but not limited
to, recent third party comparable sales and discounted cash flow models. Significant changes in
market conditions resulting from events such as the condition of an asset or a change in
managements intent to utilize the asset would generally require management to reassess the cash
flows related to the long-lived assets.
Upon classification as held for sale, a long-lived asset is measured at the lower of its
carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately
presented on the consolidated balance sheet.
Unamortized Debt Premium, Discount and Expense Premiums, discounts and expenses incurred
with the issuance of long-term debt are amortized over the terms of the debt using the effective
interest method. These premiums and discounts are recorded on the consolidated balance sheet within
long-term debt. These unamortized expenses are recorded on the consolidated balance sheet as other
long-term assets.
Fair Value Measurements We measure our derivative financial assets and liabilities related
to our commodity trading activity and our interest rate swaps at fair value as of each balance
sheet date. While we utilize as much information as is readily observable in the marketplace in
determining fair value, to the extent that information is not available we may use a combination of
indirectly observable facts or, in certain instances may develop our own expectation of the fair
value. Calculating the fair value of an instrument is a highly subjective process and involves a
significant level of judgment based on our interpretation of a variety of market conditions. The
resulting fair value may be significantly different from one measurement date to the next. All
unrealized gains and losses resulting from changes in the fair value of our interest rate swaps are
recorded in the consolidated balance sheet within AOCI and long-term debt.
Distributions Under the terms of the Second Amended and Restated LLC Agreement dated July 5,
2005, as amended, or the LLC Agreement, we are required to make quarterly distributions to Spectra
Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable
income to be allocated in accordance with Internal Revenue Code Section 704(c).
This Code Section accounts for the variation between the adjusted tax basis and the fair
market value of assets contributed to the joint venture. The distribution is based on the highest
taxable income allocated to either member with a minimum of each members tax, with the other
member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both
Spectra Energy and ConocoPhillips. During the year ended December 31, 2008, we paid distributions
of $721 million, based on estimated annual taxable income allocated to the members according to
their respective ownership percentages at the date the distributions became due.
Our board of directors determines the amount of the periodic dividends to be paid to Spectra
Energy and ConocoPhillips, by considering net income, cash flow or any other criteria deemed
appropriate. The LLC Agreement restricts payment of dividends
6
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
except with the approval of both members. During the year ended December 31, 2008, we paid
dividends of $1,140 million to the members, allocated in accordance with their respective
ownership percentages.
DCP Partners considers the payment of a quarterly distribution to the holders of its common
units and subordinated units, to the extent DCP Partners has sufficient cash from its operations
after establishment of cash reserves and payment of fees and expenses, including payments to its
general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP
Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will
be prohibited from making any distributions to unitholders if it would cause an event of default,
or an event of default exists, under its credit agreement. Our limited partner interest in DCP
Partners consisted of both subordinated units and common units. The subordinated units were
entitled to receive the minimum quarterly distribution only after DCP Partners common unitholders
received the minimum quarterly distribution plus any arrearages in the payment of the minimum
quarterly distribution from prior quarters. However, the subordination period ended, and the
subordinated units were converted into common units, on a one for one basis, as certain
distribution requirements, as defined in DCP Partners partnership agreement, were met. The
subordination period had an early termination provision that permitted 50% of the subordinated
units, or 3,571,428 units, to convert into common units on a one-for-one basis in February 2008 and
permitted the other 50% of the subordinated units, or 3,571,429 units, to convert into common units
on a one-for-one basis in February 2009, following the satisfactory completion of the tests for
ending the subordination period contained in DCP Partners partnership agreement. During the year
ended December 31, 2008, DCP Partners paid distributions of approximately $45 million to its public
unitholders. In addition to our partnership interests we hold incentive distribution rights, which
entitle us to receive an increasing share of available cash as pre-defined distribution targets are
achieved.
Equity-Based Compensation Equity classified equity-based compensation cost is measured at
fair value, based on the closing unit price at grant date, and is recognized as expense over the
vesting period. Liability classified equity-based compensation cost is remeasured at each reporting
date at fair value, based on the closing common unit price, and is recognized as expense over the
requisite service period. Compensation expense for awards with graded vesting provisions is
recognized on a straight-line basis over the requisite service period of each separately vesting
portion of the award. Awards granted to non-employees for acquiring, or in conjunction with selling
goods and services, are measured at the estimated fair value of the goods or services, or the fair
value of the award, whichever is more reliably measured.
Effective January 1, 2006, we adopted the provisions of Statement of Financial Accounting
Standard, or SFAS, No. 123(R) (Revised 2004) Share-Based Payment, or SFAS 123R, which establishes
accounting for equity-based awards exchanged for employee and non-employee services. Accordingly,
equity classified equity-based compensation cost is measured at grant date, based on the fair value
of the award, and is recognized as expense over the requisite service period. Liability classified
equity-based compensation cost is remeasured at each reporting date, and is recognized over the
requisite service period.
Accounting for Sales of Units by a Subsidiary We account for sales of units by a subsidiary
by recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of
proceeds received in excess of the carrying value of the units sold. As a result, we have deferred
approximately $270 million of gain on sale of common units in DCP Partners as of December 31, 2008,
which is included in other long-term liabilities in the consolidated balance sheet. As a result of
our adoption of SFAS 160 on January 1, 2009, we will reclassify the deferred gain from long-term
liabilities to members equity in the consolidated balance sheet.
Income Taxes We are structured as a limited liability company, which is a pass-through
entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and
state corporate income tax returns. The income tax expense related to this corporation is included
in our income tax expense, along with state, local, franchise and margin taxes of the limited
liability company and other subsidiaries.
We follow the asset and liability method of accounting for income taxes. Under the asset and
liability method, deferred income taxes are recognized for the tax consequences of temporary
differences between the financial statement carrying amounts and the tax basis of the assets and
liabilities.
Recent Accounting Pronouncements Financial Accounting Standards Board, or FASB, Statement of
Financial Accounting Standards, or SFAS, No. 162 The Hierarchy of Generally Accepted Accounting
Principles, or SFAS 162 In May 2008, the FASB issued SFAS 162, which is intended to improve
financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting
principles to be used in preparing financial statements that are presented in conformity with GAAP
for nongovernmental entities. SFAS 162 is effective 60 days following the Securities and Exchange
Commission, or SECs, approval of the Public Company Accounting Oversight Board amendments to AU
Section 411, The Meaning of Present Fairly in Conformity
7
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
with Generally Accepted Accounting Principles. We have assessed the impact of the adoption of
SFAS 162, and believe that there will be no impact on our consolidated results of operations, cash
flows or financial position.
FASB Staff Position, or FSP No. SFAS 142-3 Determination of the Useful Life of Intangible
Assets, or FSP 142-3 In April 2008, the FASB issued FSP 142-3 which amends the factors that
should be considered in developing renewal or extension assumptions used to determine the useful
life of a recognized intangible. FSP 142-3 is effective for financial statements issued for fiscal
years beginning after December 15, 2008, and interim periods within those fiscal years. We are in
the process of assessing the impact of FSP 142-3 but do not expect a material impact on our
consolidated results of operations, cash flows and financial position as a result of adoption.
SFAS No. 161 Disclosures about Derivative Instruments and Hedging Activitiesan amendment of
FASB Statement No. 133 or SFAS 161 In March 2008, the FASB issued SFAS 161, which requires
disclosures of how and why an entity uses derivative instruments, how derivative instruments and
related hedged items are accounted for and how derivative instruments and related hedged items
affect an entitys financial position, financial performance, and cash flows. SFAS 161 is effective
for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our
disclosures, and will make the required disclosures in our March 31, 2009 consolidated financial
statements.
SFAS No. 160 Noncontrolling Interests in Consolidated Financial Statements, an amendment of
Accounting Research Bulletin No. 51, or SFAS 160 In December 2007, the FASB issued SFAS 160,
which establishes accounting and reporting standards for ownership interests in subsidiaries held
by parties other than the parent, the amount of consolidated net income attributable to the parent
and to the noncontrolling interest, changes in a parents ownership interest and the valuation of
retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also
establishes reporting requirements that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS 160 was effective for us on January 1, 2009 and did not have a significant impact on our
consolidated results of operations, cash flows or financial position. As a result of adoption,
effective January 1, 2009 we will reclassify our non-controlling interest and deferred gain
relating to the sale of common units in DCP Partners to members equity.
SFAS No. 141(R) Business Combinations (revised 2007), or SFAS 141(R) In December 2007, the
FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize
all (and only) the assets acquired and liabilities assumed in the transaction; establishes the
acquisition-date fair value as the measurement objective for all assets acquired and liabilities
assumed; and requires the acquirer to disclose to investors and other users all of the information
they need to evaluate and understand the nature and financial effect of the business combination.
SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively
upon adoption, we will account for all transactions with closing dates subsequent to the adoption
date in accordance with the provisions of the standard.
SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilitiesincluding
an amendment of FAS 115, or SFAS 159 In February 2007, the FASB issued SFAS 159, which allows
entities to choose, at specified election dates, to measure eligible financial assets and
liabilities at fair value that are not otherwise required to be measured at fair value. If a
company elects the fair value option for an eligible item, changes in that items fair value in
subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes
presentation and disclosure requirements designed to draw comparison between entities that elect
different measurement attributes for similar assets and liabilities. SFAS 159 became effective for
us on January 1, 2008. We have not elected the fair value option relative to any of our financial
assets and liabilities which are not otherwise required to be measured at fair value by other
accounting standards. Therefore, there is no effect of adoption reflected in our consolidated
results of operations, cash flows or financial position.
SFAS No. 157, Fair Value Measurements, or SFAS 157 In September 2006, the FASB issued SFAS
157, which was effective for us on January 1, 2008. SFAS 157:
|
|
|
defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the
measurement date; |
|
|
|
|
establishes a framework for measuring fair value; |
|
|
|
|
establishes a three-level hierarchy for fair value measurements based upon the
transparency of inputs to the valuation of an asset or liability as of the measurement
date; |
|
|
|
|
nullifies the guidance in Emerging Issues Task Force, or EITF, 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy
Trading and Risk Management Activities, which required the deferral of |
8
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
|
|
|
profit at inception of a transaction involving a derivative financial instrument in the
absence of observable data supporting the valuation technique; and |
|
|
|
|
significantly expands the disclosure requirements around instruments measured at fair
value. |
Upon the adoption of this standard we incorporated the marketplace participant view as
prescribed by SFAS 157. Such changes included, but were not limited to, changes in valuation
policies to reflect an exit price methodology, the effect of considering our own non-performance
risk on the valuation of liabilities, and the effect of any change in our credit rating or
standing. As a result of adopting SFAS 157, we recorded a transition adjustment of approximately $2
million as an increase to earnings during the three months ended March 31, 2008. All changes in our
valuation methodology have been incorporated into our fair value calculations subsequent to
adoption.
Pursuant to FASB Staff Position 157-2, the FASB issued a partial deferral, ending on December
31, 2008, of the implementation of SFAS 157 as it relates to all non-financial assets and
liabilities where fair value is the required measurement attribute by other accounting standards.
While we have adopted SFAS 157 for all financial assets and liabilities effective January 1, 2008,
we are in the process of assessing the impact SFAS 157 will have on our non-financial assets and
liabilities, but do not expect a material impact on our consolidated results of operations, cash
flows or financial positions upon adoption.
FSP, No. 157-3 Determining the Fair Value of a Financial Asset When the Market for That Asset
is Not Active, or FSP 157-3 In October 2008, the FASB issued FSP 157-3, which provides guidance
in situations where a) observable inputs do not exist, b) observable inputs exist but only in an
inactive market and c) how market quotes should be considered when assessing the relevance of
observable and unobservable inputs to determine fair value. FSP 157-3 was effective upon issuance,
including prior periods for which financial statements have not been issued. We believe that the
financial assets that are reflected in our financial statements are transacted within active
markets, and therefore, there is no effect on our consolidated results of operations, cash flows or
financial positions as a result of the adoption of this FSP.
FSP of Financial Interpretation, or FIN, 39-1, Amendment of FASB Interpretation No. 39, or
FSP FIN 39-1 In April 2008 the FASB issued FSP FIN 39-1, which permits, but does not require, a
reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral
(a receivable) or the obligation to return cash collateral (a payable) against the fair value
amounts recognized for derivative instruments executed with the same counterparty under a master
netting arrangement. FSP 39-1 became effective for us beginning on January 1, 2008; however, we
have elected to continue our policy of reflecting our derivative asset and liability positions, as
well as any cash collateral, on a gross basis in our consolidated balance sheet.
EITF, 08-06 Equity Method Investment Accounting Considerations, or EITF 08-06 In November
2008, the EITF issued
ETIF 08-06. Although the issuance of FAS 141(R) and FAS 160 were not
intended to reconsider the accounting for equity method investments, the application of the equity
method is affected by the issuance of these standards. This issue addresses a) how the initial
carrying value of an equity method investment should be determined; b) how an impairment assessment
of an underlying indefinite-lived intangible asset of an equity method investment should be
performed; c) how an equity method investees issuance of shares should be accounted for and d) how
to account for a change in an investment from the equity method to the cost method. This issue is
effective for us effective January 1, 2009, and although we do not expect any changes to the manner
in which we apply equity method accounting, this guidance will be considered on a prospective basis
to transactions with equity method investees.
9
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
2. Acquisitions and Dispositions
Acquisitions
Acquisition of Various Gathering, Pipeline and Compression Assets On October 1, 2008, DCP
Partners acquired Michigan Pipeline & Processing, LLC, or MPP, a privately held company engaged in
natural gas gathering and treating services for natural gas produced from the Antrim Shale of
northern Michigan and natural gas transportation within Michigan. The results of MPPs operations
have been included in the consolidated financial statements since that date. Under the terms of the
acquisition, DCP Partners paid a purchase price of $145 million, plus net working capital and other
adjustments of approximately $3 million, subject to additional customary purchase price
adjustments. DCP Partners may pay up to an additional $15 million to the sellers depending on the
earnings of the assets after a three-year period. DCP Partners financed the acquisition by
liquidating a portion of its restricted investments. In addition, DCP Partners entered into a
separate agreement that provides the seller with available treating capacity on certain Michigan
assets. The seller agreed to pay DCP Partners up to approximately $2 million annually for up to
nine years if they do not meet certain criteria, including providing additional volumes for
treatment. These payments would reduce goodwill as a return of purchase price. This agreement may
be terminated earlier if certain performance criteria of Michigan assets are satisfied. Certain of
these performance criteria were satisfied and, as a result, the amount the seller will pay DCP
Partners has been reduced to approximately $1 million per year as of December 31, 2008. DCP
Partners initially held a $25 million letter of credit to secure the sellers contingent future
performance under this agreement and to secure the sellers indemnification obligation under the
acquisition agreement; however as a result of the satisfaction of certain performance conditions,
this amount was reduced to approximately $23 million as of December 31, 2008.
Under the purchase method of accounting, the assets and liabilities of MPP were recorded at
their respective fair values as of the date of the acquisition, and we recorded goodwill of
approximately $6 million. The goodwill amount recognized relates primarily to projected growth from
new customers. The values of certain assets and liabilities are preliminary, and are subject to
adjustments as additional information is obtained. When finalized, material adjustments may result.
The purchase price allocation is as follows:
|
|
|
|
|
|
|
(Millions) |
|
Cash |
|
$ |
2 |
|
Accounts receivable |
|
|
2 |
|
Property, plant and equipment |
|
|
116 |
|
Goodwill |
|
|
6 |
|
Intangible assets |
|
|
20 |
|
Other long-term assets |
|
|
4 |
|
Non-controlling interest |
|
|
(2 |
) |
|
|
|
|
Total purchase price allocation |
|
$ |
148 |
|
|
|
|
|
In October 2008, we acquired certain pipeline and compressor station assets located in Kansas,
Oklahoma and Texas from Northern Natural Gas for $49 million.
On August 29, 2007, we acquired the stock of Momentum Energy Group, Inc., or MEG, for
approximately $635 million plus closing adjustments of approximately $11 million. The results of
MEGs operations have been included in the consolidated financial statements since that date. As a
result of the acquisition, we expanded our operations into the Fort Worth, Piceance and Powder
River producing basins, thus diversifying our business into new areas. We funded our portion of
this acquisition with a 364-day bridge loan for $450 million, which was paid off in September 2007
with proceeds from the issuance of the $450 million principal amount of 6.75% Senior Notes, as well
as cash on hand. See further discussion of this transaction in the Contributions to DCP Partners
section below.
Under the purchase method of accounting, the assets and liabilities of MEG were recorded at
their respective fair values as of the date of the acquisition, and we recorded goodwill of
approximately $138 million, including purchase price adjustments of $3 million during the first
quarter of 2008. The goodwill amount recognized relates primarily to projected growth in the Fort
Worth and Piceance producing basins due to significant natural gas reserves and high level of
drilling activity.
10
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
The purchase price allocation is as follows (in millions):
|
|
|
|
|
Cash |
|
$ |
42 |
|
Receivables |
|
|
23 |
|
Other assets |
|
|
2 |
|
Property, plant and equipment |
|
|
282 |
|
Intangible assets |
|
|
254 |
|
Goodwill |
|
|
138 |
|
Payables |
|
|
(18 |
) |
Other liabilities |
|
|
(34 |
) |
Current debt |
|
|
(20 |
) |
Non-controlling interest |
|
|
(23 |
) |
|
|
|
|
Total purchase price allocation |
|
$ |
646 |
|
|
|
|
|
Dispositions
Disposition of Investments in Unconsolidated Affiliates In October 2008, we sold certain
interests in unconsolidated affiliates to unrelated third parties for $19 million in cash, subject
to purchase price adjustments, and recognized a gain of $11 million.
Contributions to DCP Partners
MEG Concurrent with our acquisition of the stock of MEG in August 2007, DCP Partners
acquired certain subsidiaries of MEG from us for $166 million plus post-closing purchase price
adjustments of approximately $9 million. These subsidiaries of MEG own assets in the Piceance
Basin, including a 70% operated interest in the Collbran Valley Gas Gathering joint venture in
western Colorado, and assets in the Powder River Basin, including the Douglas gas gathering system
in Wyoming. DCP Partners financed this transaction with $120 million of borrowings under the DCP
Partners Credit Agreement, the issuance of common units through a private placement with certain
institutional investors and cash on hand. In August 2007, DCP Partners issued 2,380,952 common
limited partner units in a private placement, pursuant to a common unit purchase agreement with
private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100
million in the aggregate. These units were registered with the SEC in January 2008. As a result of
this transaction, the omnibus agreement with DCP Partners was amended to increase the annual fee
payable to us by DCP Partners by $2 million for incremental general and administrative expenses. We
operate these assets and they are included in our financial statements, through the consolidation
of DCP Partners.
DCP East Texas Holdings, LLC and Discovery Producer Services LLC In July 2007, we
contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings,
LLC, or East Texas, our 40% limited liability company interest in Discovery Producer Services LLC,
or Discovery, and a derivative instrument, for aggregate consideration of $244 million in cash,
including $1 million for net working capital and other adjustments, $27 million in common units and
$1 million in general partner equivalent units. We own the remaining 75% limited liability company
interest in East Texas, while third parties still own the other 60% limited liability interest in
Discovery. DCP Partners financed the cash portion of this transaction with borrowings under its
existing credit facility. We will continue to operate East Texas and both of these assets will
continue to be included in our financial statements, through the consolidation of DCP Partners. In
December of 2008, we announced that we will contribute an additional 25% ownership interest in East
Texas to DCP Partners in exchange for 100% DCP Partners common units. This transaction is expected
to close in April 2009.
3. Agreements and Transactions with Affiliates
ConocoPhillips
Long-term NGL Purchases Contract and Transactions We sell a portion of our residue gas and
NGLs to ConocoPhillips and its subsidiaries, including ChevronPhillips Chemical Company LLC, or CP
Chem, a 50% equity investment of ConocoPhillips. In addition, we purchase natural gas from
ConocoPhillips. Under the NGL Output Purchase and Sale Agreements, or the NGL Agreements, with
ConocoPhillips and CP Chem, ConocoPhillips and CP Chem have the right to purchase at index-based
prices substantially all NGLs produced by our various processing plants located in the
Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40%
of our total NGL production. The NGL Agreements also grant ConocoPhillips and CP Chem the right to
purchase at index-based prices certain quantities of NGLs produced at processing plants that are
acquired
11
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
and/or constructed by us in the future in various counties in the Mid-Continent and Permian
Basin regions, and the Austin Chalk area. The primary terms of the agreements are effective until
January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these
services to ConocoPhillips and CP Chem in the ordinary course of business.
Spectra Energy
Commodity Transactions We sell a portion of our residue gas and NGLs to, purchase natural
gas and other petroleum products from, and provide gathering, transportation and other services to
Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell
commodities and provide services to Spectra Energy in the ordinary course of business.
Included in the consolidated balance sheet in accounts receivableaffiliates as of December
31, 2008 are insurance recovery receivables of approximately $13 million.
During the second quarter of 2008, DCP Partners entered into a propane supply agreement with
Spectra Energy. This agreement, effective May 1, 2008 and terminating April 30, 2014, provides DCP
Partners propane supply at their marine terminal for up to approximately 120 million gallons of
propane annually. This contract replaces the supply provided under a contract with a third party
that was terminated during the first quarter of 2008.
Transactions with other unconsolidated affiliates
We sell a portion of our residue gas and NGLs to, purchase natural gas and other petroleum
products from, and provide gathering and transportation services to, unconsolidated affiliates. We
anticipate continuing to purchase and sell commodities and provide services to unconsolidated
affiliates in the ordinary course of business.
4. Inventories
Inventories were as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Natural gas held for resale |
|
$ |
7 |
|
NGLs |
|
|
36 |
|
|
|
|
|
Total inventories |
|
$ |
43 |
|
|
|
|
|
5. Property, Plant and Equipment
Property, plant and equipment by classification was as follows:
|
|
|
|
|
|
|
|
|
|
|
Depreciable |
|
|
December 31, |
|
|
|
Life |
|
|
2008 |
|
|
|
|
|
|
|
(millions) |
|
Gathering |
|
15 - 30 years |
|
$ |
3,633 |
|
Processing |
|
25 - 30 years |
|
|
2,134 |
|
Transportation |
|
25 - 30 years |
|
|
1,329 |
|
Underground storage |
|
20 - 50 years |
|
|
141 |
|
General plant |
|
3 - 5 years |
|
|
219 |
|
Construction work in progress |
|
|
|
|
|
|
367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,823 |
|
Accumulated depreciation |
|
|
|
|
|
|
(2,987 |
) |
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
$ |
4,836 |
|
|
|
|
|
|
|
|
|
Interest capitalized on construction projects in 2008 was approximately $10 million. At
December 31, 2008, we had non-cancelable purchase obligations of approximately $83 million for
capital projects anticipated to be completed in 2009.
12
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
DCP Partners leases one of the MPP transmission pipelines to a third party under a long-term
contract. The carrying value of the pipeline is approximately $23 million, with accumulated
depreciation of less than $1 million. Minimum future non-cancelable rental payments are as follows:
|
|
|
|
|
(millions) |
|
2009 |
|
$ |
3 |
|
2010 |
|
|
3 |
|
2011 |
|
|
3 |
|
2012 |
|
|
3 |
|
2013 |
|
|
2 |
|
Thereafter |
|
|
21 |
|
|
|
|
|
Total |
|
$ |
35 |
|
|
|
|
|
6. Goodwill and Intangible Assets
The changes in carrying amount of goodwill are as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Goodwill, beginning of period |
|
$ |
556 |
|
Acquisitions |
|
|
9 |
|
|
|
|
|
Goodwill, end of period |
|
$ |
565 |
|
|
|
|
|
Goodwill increased by $6 million during 2008 as a result of the amount that we recognized in
connection with our acquisition of MPP, and by $3 million for the final purchase price allocation
for the MEG acquisition.
We perform an annual goodwill impairment test, and update the test during interim periods if
events or circumstances occur that would more likely than not reduce the fair value of a reporting
unit below its carrying amount. We use a discounted cash flow analysis supported by market
valuation multiples to perform the assessment. Key assumptions in the analysis include the use of
an appropriate discount rate, estimated future cash flows and an estimated run rate of general and
administrative costs. In estimating cash flows, we incorporate current market information, as well
as historical and other factors, into our forecasted commodity prices. Our annual goodwill
impairment test, as of August 31, 2008 indicated that our reporting units fair values exceed their
carrying or book values. Accordingly, no impairment of goodwill is indicated. During the fourth
quarter of 2008, as a result of the decline in the unit price of DCP Partners units on the New
York Stock Exchange, we updated our fair value analysis of the DCP Partners reporting unit using
current marketplace assumptions and concluded that the carrying value of the goodwill associated
with these units is recoverable. However, given the current volatility in the market, as well as
volatile commodity prices, we will continue to monitor the recoverability of such amounts.
Continued volatility and marketplace activity may alter our conclusion in the future, and could
result in the recognition of an impairment charge.
Intangible assets consist primarily of customer contracts and related relationships, including
commodity purchase, transportation and processing contracts. The gross carrying amount and
accumulated amortization for intangible assets are as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Gross carrying amount |
|
$ |
426 |
|
Accumulated amortization |
|
|
(107 |
) |
|
|
|
|
Intangible assets, net |
|
$ |
319 |
|
|
|
|
|
Intangible assets increased by $20 million in 2008 as a result of the MPP acquisition. The
remaining amortization periods range from less than one year to 25 years, with a weighted average
remaining period of approximately 21 years.
13
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Estimated amortization for these contracts for the next five years and thereafter is as
follows as of December 31, 2008:
|
|
|
|
|
Estimated Amortization |
|
(millions) |
|
2009 |
|
$ |
21 |
|
2010 |
|
|
21 |
|
2011 |
|
|
20 |
|
2012 |
|
|
20 |
|
2013 |
|
|
20 |
|
Thereafter |
|
|
217 |
|
|
|
|
|
Total |
|
$ |
319 |
|
|
|
|
|
7. Investments in Unconsolidated Affiliates
We have investments in the following unconsolidated affiliates accounted for using the equity
method:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
December 31, |
|
|
|
Ownership |
|
|
2008 |
|
|
|
|
|
|
|
(millions) |
|
Discovery Producer Services LLC |
|
|
40.00 |
% |
|
$ |
105 |
|
Main Pass Oil Gathering Company |
|
|
66.67 |
% |
|
|
43 |
|
Mont Belvieu I |
|
|
20.00 |
% |
|
|
11 |
|
Sycamore Gas System General Partnership |
|
|
48.45 |
% |
|
|
10 |
|
Other unconsolidated affiliates |
|
Various |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
Total investments in unconsolidated affiliates |
|
|
|
|
|
$ |
179 |
|
|
|
|
|
|
|
|
|
Discovery Producer Services LLC Discovery operates a cryogenic natural gas processing plant
near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana with a
design capacity of 600 MMcf/d and approximately 280 miles of pipe, and several onshore laterals
expanding their presence in the Gulf. The deficit between the carrying amount of the investment and
the underlying equity of Discovery of $40 million at December 31, 2008, is associated with, and is
being depreciated over the life of, the underlying long-lived assets of Discovery.
Main Pass Oil Gathering Company In December 2006, we acquired an additional 33.33% interest
in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in
the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main
Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have
the ability to exercise control, we continue to account for Main Pass under the equity method. The
excess of the carrying amount of the investment over the underlying equity of Main Pass of $11
million at December 31, 2008, is associated with, and is being depreciated over the life of, the
underlying long-lived assets of Main Pass.
Mont Belvieu I Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu,
Texas Market Center. The deficit between the carrying amount of the investment and the underlying
equity of Mont Belvieu I of $9 million at December 31, 2008, is associated with, and is being
depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.
Sycamore Gas System General Partnership Sycamore Gas System General Partnership, or
Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas
gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of
the investment over the underlying equity of Sycamore of $6 million at December 31, 2008 is
associated with, and is being depreciated over the life of, the underlying long-lived assets of
Sycamore.
14
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
The following summarizes combined balance sheet information of unconsolidated affiliates:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Balance sheet: |
|
|
|
|
Current assets |
|
$ |
86 |
|
Long-term assets |
|
|
542 |
|
Current liabilities |
|
|
(60 |
) |
Long-term liabilities |
|
|
(26 |
) |
|
|
|
|
Net assets |
|
$ |
542 |
|
|
|
|
|
8. Fair Value Measurement
Determination of Fair Value
Below is a general description of our valuation methodologies for derivative financial assets
and liabilities, as well as short term and restricted investments, which are measured at fair
value. Fair values are generally based upon quoted market prices, where available. In the event
that listed market prices or quotes are not available, we determine fair value based upon a market
quote, adjusted by other market-based or independently sourced market data such as historical
commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations.
These adjustments result in a fair value for each asset or liability under an exit price
methodology, in line with how we believe a marketplace participant would value that asset or
liability. These adjustments may include amounts to reflect counterparty credit quality, the effect
of our own creditworthiness, the time value of money, and/or liquidity of the market.
|
|
|
Counterparty credit valuation adjustments are necessary when the market price of an
instrument is not indicative of the fair value as a result of the credit quality of the
counterparty. Generally, market quotes assume that all counterparties have near zero, or
low, default rates and have equal credit quality. Therefore, an adjustment may be necessary
to reflect the credit quality of a specific counterparty to determine the fair value of the
instrument. We record counterparty credit valuation adjustments on all derivatives that are
in a net asset position as of the measurement date in accordance with our established
counterparty credit policy, which takes into account any collateral margin that a
counterparty may have posted with us. |
|
|
|
|
Entity valuation adjustments are necessary to reflect the effect of our own credit
quality on the fair value of our net liability position with each counterparty. This
adjustment takes into account any credit enhancements, such as collateral margin that we
may have posted with a counterparty, as well as any letters of credit that we have
provided. The methodology to determine this adjustment is consistent with how we evaluate
counterparty credit risk, taking into account our own credit rating, current credit
spreads, as well as any change in such spreads since the last measurement date. |
|
|
|
|
Liquidity valuation adjustments are necessary when we are not able to observe a recent
market price for financial instruments that trade in less active markets, for the fair
value to reflect the cost of exiting the position. Exchange traded contracts are valued at
market value without making any additional valuation adjustments and, therefore, no
liquidity reserve is applied. For contracts other than exchange traded instruments, we mark
our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based
upon our total net position. We believe that such practice results in the most reliable
fair value measurement as viewed by a market participant. |
We manage our derivative instruments on a portfolio basis and the valuation adjustments
described above are calculated on this basis. We believe that the portfolio level approach
represents the highest and best use for these assets as there are benefits inherent in naturally
offsetting positions within the portfolio at any given time, and this approach is consistent with
how a market participant would view and value the assets. Although we take a portfolio approach to
managing these assets/liabilities, in order to reflect the fair value of any one individual
contract within the portfolio, we allocate all valuation adjustments down to the contract level; to
the extent deemed necessary, based upon either the notional contract volume, or the contract value,
whichever is more applicable.
The methods described above may produce a fair value calculation that may not be indicative of
net realizable value or reflective of future fair values. While we believe that our valuation
methods are appropriate and consistent with other marketplace participants,
15
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
we recognize that the use of different methodologies or assumptions to determine the fair
value of certain financial instruments could result in a different estimate of fair value at the
reporting date. We review our fair value policies on a regular basis, taking into consideration
changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 12,
Risk Management and Hedging Activities, Credit Risk and Financial Instruments.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation
hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of
the measurement date. The three levels are defined as follows.
|
|
|
Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in
active markets. |
|
|
|
|
Level 2 inputs include quoted prices for similar assets and liabilities in active
markets, and inputs that are observable for the asset or liability, either directly or
indirectly, for substantially the full term of the financial instrument. |
|
|
|
|
Level 3 inputs are unobservable and considered significant to the fair value
measurement. |
A financial instruments categorization within the hierarchy is based upon the lowest level of
input that is significant to the fair value measurement. Following is a description of the
valuation methodologies used as well as the general classification of such instruments pursuant to
the hierarchy.
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include exchange traded
instruments (such as New York Mercantile Exchange, or NYMEX, crude oil, or natural gas futures) or
over the counter instruments, or OTC, instruments (such as natural gas contracts, crude oil or NGL
swaps). The exchange traded instruments are generally executed on the NYMEX exchange with a highly
rated broker dealer serving as the clearinghouse for individual transactions.
Our activities expose us to varying degrees of commodity price risk exposure. To mitigate a
portion of this risk, and to manage commodity price risk related primarily, to owned natural gas
storage and pipeline assets we engage in natural gas asset based trading and marketing, we may
enter into natural gas and crude oil derivatives to lock in a specific margin when market
conditions are favorable. A portion of this may be accomplished through the use of exchange traded
derivative contracts. Such instruments are generally classified as Level 1 since the value is equal
to the quoted market price of the exchange traded instrument as of our balance sheet date, and no
adjustments are required. Depending upon market conditions and our strategy we may enter into
exchange traded derivative positions with a significant time horizon to maturity. Although such
instruments are exchange traded, market prices may only be readily observable for a portion of the
duration of the instrument. In order to calculate the fair value of these instruments, readily
observable market information is utilized to the extent that it is available; however, in the event
that readily observable market data is not available, we may interpolate based upon observable
data. In instances where we utilize an interpolated value, and it is considered significant to the
valuation of the contract as a whole, we would classify the instrument within Level 2. In certain
limited instances, we may extrapolate based upon the last readily observable data, developing our
own expectation of fair value. To the extent that we have utilized extrapolated data, and it is
considered significant to the valuation of the contract as a whole, we would classify the
instrument within Level 3.
We also engage in the business of trading energy related products and services, which expose
us to market variables and commodity price risk. We may enter into physical contracts or financial
instruments with the objective of realizing a positive margin from the purchase and sale of these
commodity-based instruments. We may enter into derivative instruments for NGLs or other energy
related products, primarily using the OTC derivative instrument markets, which may not be as active
and liquid as exchange traded instruments. Market quotes for such contracts may only be available
for short dated positions (up to six months), and a market itself may not exist beyond such time
horizon. Contracts entered into with a relatively short time horizon for which prices are readily
observable in the OTC market, are generally classified within Level 2. Contracts with a longer time
horizon, for which we internally generate a forward curve to value such instruments, are generally
classified within Level 3. The internally generated curve may utilize a variety of assumptions
including, but not limited to, historical and future expected correlation of NGL prices to crude
oil, the knowledge of expected supply sources coming on line, expected weather trends within
certain regions of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial
quarter depending upon the extent to which the valuation inputs are observable. Generally, an
instrument will move toward a level within the hierarchy that requires a lower
16
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
degree of judgment as the time to maturity approaches, and as the markets in which the asset
trades will likely become more liquid and prices more readily available in the market, thus
reducing the need to rely upon our internally developed assumptions. However, the level of a given
instrument may change, in either direction, depending upon market conditions and the availability
of market observable data.
Interest Rate Derivative Assets and Liabilities
We have interest rate swap agreements as part of our overall capital strategy. These
instruments effectively exchange a portion of our floating rate debt for fixed rate debt or our
fixed rate debt for floating rate debt, and are held with major financial institutions, which are
expected to fully perform under the terms of our agreements. The swaps are generally priced based
upon a United States Treasury instrument with similar characteristics, adjusted by the credit
spread between our company and the United States Treasury instrument. Given that a significant
portion of the swap value is derived from the credit spread, which may be observed by comparing
similar assets in the market, these instruments are classified as Level 2. Default risk on either
side of the swap transaction is also considered in the valuation. We record counterparty credit,
our entity valuation, as well as liquidity reserves in the valuation of our interest rate swaps;
however, these reserves are not considered to be a significant input to the overall valuation.
Restricted Investments
We are required to post collateral to secure the term loan portion of DCP Partners credit
facility, and may elect to invest a portion of our available cash balances in various financial
instruments such as commercial paper, money market instruments and highly rated debt securities
that have stated maturities of 20 years or more, which are categorized as available-for-sale
securities. The money market instruments are generally priced at acquisition cost, plus accreted
interest at the stated rate, which approximates fair value, without any additional adjustments.
However, given that there is no observable exchange traded market for identical money market
securities, we have classified these instruments within Level 2. Investments in commercial paper
and highly rated debt securities are priced using a yield curve for similarly rated instruments,
and are classified within Level 2. As of December 31, 2008, nearly all of our restricted
investments were held in the form of money market securities. By virtue of our balances in these
funds on September 19, 2008, all of these investments are eligible for, and the funds are
participating in, the U.S. Treasury Departments Guarantee Program for Money Market Funds.
17
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
The following table presents the financial instruments carried at fair value as of December
31, 2008, by consolidated balance sheet caption and by valuation hierarchy, as described above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal |
|
Internal |
|
|
|
|
Quoted |
|
Models With |
|
Models With |
|
|
|
|
Market Prices |
|
Significant |
|
Significant |
|
|
|
|
in Active |
|
Observable |
|
Unobservable |
|
Total |
|
|
Markets |
|
Market Inputs |
|
Market Inputs |
|
Carrying |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Value |
|
|
(millions) |
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments (a) |
|
$ |
34 |
|
|
$ |
175 |
|
|
$ |
210 |
|
|
$ |
419 |
|
Available-for-sale securities (b) |
|
$ |
|
|
|
$ |
15 |
|
|
$ |
|
|
|
$ |
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments (c) |
|
$ |
61 |
|
|
$ |
36 |
|
|
$ |
22 |
|
|
$ |
119 |
|
Restricted investments |
|
$ |
|
|
|
$ |
60 |
|
|
$ |
|
|
|
$ |
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities (d): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments |
|
$ |
(79 |
) |
|
$ |
(145 |
) |
|
$ |
(155 |
) |
|
$ |
(379 |
) |
Interest rate instruments |
|
$ |
|
|
|
$ |
(19 |
) |
|
$ |
|
|
|
$ |
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities (e): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments |
|
$ |
(8 |
) |
|
$ |
(6 |
) |
|
$ |
(44 |
) |
|
$ |
(58 |
) |
Interest rate instruments |
|
$ |
|
|
|
$ |
(23 |
) |
|
$ |
|
|
|
$ |
(23 |
) |
|
|
|
(a) |
|
Included in current unrealized gains on derivative instruments in our consolidated balance sheet. |
|
(b) |
|
Included in cash and cash equivalents in our consolidated balance sheet. |
|
(c) |
|
Included in long-term unrealized gains on derivative instruments in our consolidated balance sheet. |
|
(d) |
|
Included in current unrealized losses on derivative instruments in our consolidated balance sheet. |
|
(e) |
|
Included in long-term unrealized losses on derivative instruments in our consolidated balance sheet. |
Changes in Level 3 Fair Value Measurements
The table below illustrates a rollforward of the amounts included in our consolidated balance
sheet for derivative financial instruments that we have classified within Level 3. The
determination to classify a financial instrument within Level 3 is based upon the significance of
the unobservable factors used in determining the overall fair value of the instrument. Since
financial instruments classified as Level 3 typically include a combination of observable
components (that is, components that are actively quoted and can be validated to external sources)
and unobservable components, the gains and losses in the table below may include changes in fair
value due in part to observable market factors, or changes to our assumptions on the unobservable
components. Depending upon the information readily observable in the market, and/or the use of
unobservable inputs, which are significant to the overall valuation, the classification of any
individual financial instrument may differ from one measurement date to the next. In the event that
there is a movement to/from the classification of an instrument as Level 3, we have reflected such
items in the table below within the Transfers In/Out of Level 3 caption.
18
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
We manage our overall risk at the portfolio level, and in the execution of our strategy, we
may use a combination of financial instruments, which may be classified within any level. Since
Level 1 and Level 2 risk management instruments are not included in the rollforward below, the
gains or losses in the table do not reflect the effect of our total risk management activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Realized and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
Purchases, |
|
|
|
|
|
|
Balance at |
|
Gains (Losses) |
|
Transfers |
|
Issuances and |
|
Balance at |
|
|
December 31, |
|
Included in |
|
In/Out of |
|
Settlements, |
|
December 31, |
|
|
2007 |
|
Earnings |
|
Level 3 (a) |
|
Net |
|
2008 |
Commodity derivative instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
125 |
|
|
$ |
143 |
|
|
$ |
|
|
|
$ |
(58 |
) |
|
$ |
210 |
|
Long-term assets |
|
$ |
21 |
|
|
$ |
2 |
|
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
22 |
|
Current liabilities |
|
$ |
(112 |
) |
|
$ |
(101 |
) |
|
$ |
|
|
|
$ |
58 |
|
|
$ |
(155 |
) |
Long-term liabilities |
|
$ |
(11 |
) |
|
$ |
(33 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(44 |
) |
|
|
|
(a) |
|
Amounts transferred in are reflected at fair value as of the end of the period and amounts transferred out are reflected at fair value at the
beginning of the period. |
9. Estimated Fair Value of Financial Instruments
We have determined the following fair value amounts using available market information and
appropriate valuation methodologies. Considerable judgment is required, however, in interpreting
market data to develop the estimates of fair value. Accordingly, the estimates presented herein are
not necessarily indicative of the amounts that we could realize in a current market exchange. The
use of different market assumptions and/or estimation methods may have a material effect on the
estimated fair value amounts.
The fair value of short-term investments, restricted investments, accounts receivable,
accounts payable and short-term borrowings are not materially different from their carrying amounts
because of the short-term nature of these instruments or the stated rates approximating market
rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried
at fair value.
The estimated fair values of current debt, including current maturities of long-term debt, and
long-term debt, with the exception of DCP Partners long-term debt, are determined by prices
obtained from market quotes. The carrying value of DCP Partners long-term debt approximates fair
value, as the interest rate is variable and reflects current market conditions. The estimated fair
value of long-term debt was $3,286 as of December 31, 2008.
10. Asset Retirement Obligations
Our asset retirement obligations relate primarily to the retirement of various gathering
pipelines and processing facilities, obligations related to right-of-way easement agreements, and
contractual leases for land use. We recognize the fair value of a liability for an asset retirement
obligation in the period in which it is incurred, if a reasonable estimate of fair value can be
made. The fair value of the liability is added to the carrying amount of the associated asset. This
additional carrying amount is then depreciated over the life of the asset. The liability increases
due to the passage of time based on the time value of money until the obligation is settled.
We identified various assets as having an indeterminate life, for which there is no
requirement to establish a fair value for future retirement obligations associated with such
assets. These assets include certain pipelines, gathering systems and processing facilities. A
liability for these asset retirement obligations will be recorded only if and when a future
retirement obligation with a determinable life is identified. These assets have an indeterminate
life because they are owned and will operate for an indeterminate future period when properly
maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified
or dismantled, we would be legally required to remove the asbestos. We currently have no plans to
take actions that would require the removal of the asbestos in these assets. Accordingly, the fair
value of the asset retirement obligation related to this asbestos cannot be estimated and no
obligation has been recorded.
19
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
The asset retirement obligation is adjusted each quarter for any liabilities incurred or
settled during the period, accretion expense and any revisions made to the estimated cash flows.
The following table summarizes changes in the asset retirement obligation, included in other
long-term liabilities in the consolidated balance sheet:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Balance, beginning of period |
|
$ |
59 |
|
Accretion expense |
|
|
5 |
|
Liabilities incurred |
|
|
5 |
|
Liabilities settled |
|
|
(1 |
) |
|
|
|
|
Balance, end of period |
|
$ |
68 |
|
|
|
|
|
11. Financing
Long-term debt was as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Debt securities: |
|
|
|
|
Issued August 2000, interest at 7.875% payable semiannually, due August 2010 |
|
$ |
800 |
|
Issued January 2001, interest at 6.875% payable semiannually, due February 2011 |
|
|
250 |
|
Issued November 2008, interest at 9.700% payable semiannually, due December 2013 |
|
|
250 |
|
Issued October 2005, interest at 5.375% payable semiannually, due October 2015 |
|
|
200 |
|
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (a) |
|
|
300 |
|
Issued October 2006, interest at 6.450% payable semiannually, due November 2036 |
|
|
300 |
|
Issued September 2007, interest at 6.750% payable semiannually, due September 2037 |
|
|
450 |
|
DCP Midstreams credit facility revolver, weighted-average interest rate of 2.69%,
due April 2012 |
|
|
360 |
|
DCP Partners credit facility revolver, weighted-average interest rate of 2.08%, due June 2012 (b) |
|
|
596 |
|
DCP Partners credit facility term loan, interest rate of 1.54%,
due June 2012 (c) |
|
|
60 |
|
Fair value adjustments related to interest rate swap fair value hedges (a) |
|
|
43 |
|
Unamortized discount |
|
|
(7 |
) |
|
|
|
|
Long-term debt |
|
$ |
3,602 |
|
|
|
|
|
|
|
|
(a) |
|
The swaps associated with this debt were terminated in December 2008. The remaining fair value adjustments of $43
million related to the swaps will be amortized as a reduction to interest expense through the maturity date of the debt. |
|
(b) |
|
$575 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%,
for a net effective rate of 4.48% on the $596 million of outstanding debt under the DCP Partners revolving credit facility
as of December 31, 2008. |
|
(c) |
|
The term loan facility is fully secured by restricted investments. |
20
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Approximate future maturities of long-term debt in the year indicated are as follows at
December 31, 2008:
|
|
|
|
|
Debt Maturities |
|
(millions) |
|
2010 |
|
$ |
800 |
|
2011 |
|
|
250 |
|
2012 |
|
|
1,016 |
|
2013 |
|
|
250 |
|
Thereafter |
|
|
1,250 |
|
|
|
|
|
|
|
|
3,566 |
|
Unamortized discount |
|
|
(7 |
) |
Fair value adjustments related to interest rate swap fair value hedges |
|
|
43 |
|
|
|
|
|
Long-term debt |
|
$ |
3,602 |
|
|
|
|
|
Debt Securities In November 2008, we issued $250 million principal amount of 9.70% Senior
Notes due 2013, or the 9.70% Notes, for proceeds of approximately $248 million, net of related
offering costs. The 9.70% Notes mature and become due and payable on December 1, 2013. We will pay
interest semiannually on June 1 and December 1 of each year, beginning June 1, 2009. We used $200
million of the proceeds of this offering to pay down our 364-day agreement that we entered into in
April 2008 and the remainder was used for general corporate purposes.
In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or
the 6.75% Notes, for proceeds of approximately $444 million, net of related offering costs. The
6.75% Notes mature and become due and payable on September 15, 2037. We pay interest semiannually
on March 15 and September 15 of each year.
The debt securities mature and become payable on the respective due dates, and are not subject
to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured
and are redeemable at our option.
DCP Midstreams Credit Facilities with Financial Institutions We have a $450 million
revolving credit facility, or the Facility, which is used to support our commercial paper program,
and for working capital and other general corporate purposes. Any outstanding borrowings under the
Facility at maturity may, at our option, be converted into an unsecured one-year term loan. The
Facility may be used for letters of credit. As of December 31, 2008 there were borrowings of $360
million outstanding under the Facility and available capacity of $82 million. There was no
commercial paper outstanding as of December 31, 2008. As of December 31, 2008, there were
approximately $8 million in letters of credit outstanding. During 2008, total outstanding
indebtedness under the Facility, including borrowings and drawn letters of credit issued under the
Facility, was not less than $0 and did not exceed $360 million. The weighted average indebtedness
outstanding under the Facility was $54 million for 2008.
Indebtedness under the Facility bears interest at a rate equal to, at our option and based on
our current debt rating, either: (1) London Interbank Offered Rate, or LIBOR, plus 0.23% per year
for the initial 50% usage or LIBOR plus 0.28% per year if usage is greater than 50%; or (2) the
higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per
year. The Facility incurs an annual facility fee of 0.07% based on our credit rating on the drawn
and undrawn portions.
In November 2008, we entered into a $350 million revolving credit facility agreement, or the
$350 Million Facility, which matures in November 2009. The $350 Million Facility may be used to
support our commercial paper program, for working capital requirements and for other general
corporate purposes. As of December 31, 2008, there were no borrowings under the $350 Million
Facility.
Indebtedness under the $350 Million Facility bears interest at a rate equal to, at our option
and based on our debt rating at December 31, 2008, (1) the higher of (a) Citibanks prime rate per
year, (b) the Federal Funds rate plus 0.5% per year, or (c) LIBOR plus 2.125% per year, with an
increase of 0.25% per quarter, up to 3.125% or (2) LIBOR plus 2.125% per year, with an increase of
0.25% per quarter, up to 3.125%. The $350 Million Facility incurs an annual facility fee of 0.625%
based on our current debt rating plus (a) 0.0% to 0.75%, escalating 0.25% quarterly, on the undrawn
portions; and (b) 0.5% to 1.75 %, escalating quarterly, on the drawn portions.
In April 2008, we entered into a $300 million 364-day credit agreement, which was fully funded
in April 2008, matures in April 2009 and is included within short-term borrowings in the
consolidated balance sheet. The proceeds were used to partially fund the
21
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
April 2008 dividend to our parents and the debt bears interest at a rate equal to, at our
option and based on our debt rating at December 31, 2008, either (1) LIBOR, plus 0.75% per year or
(2) the higher of (a) the Federal Funds Rate in effect on such day plus 0.5% per year or (b) the
JPMorgan Chase Bank prime rate per year. As of December 31, 2008 the outstanding balance under the
364-day agreement was $100 million and is classified in short-term borrowings in the accompanying
consolidated balance sheet as of December 31, 2008.
The Facility, the $350 Million Facility and the 364-day credit agreement each require that we
maintain a consolidated leverage ratio (the ratio of consolidated indebtedness to consolidated
EBITDA, in each case as is defined by these agreements) of not more than 5.0 to 1.0 and on a
temporary basis for not more than three consecutive quarters following the consummation of
qualifying asset acquisitions (as defined by the agreements) of not more than 5.5 to 1.0. Prior to
being amended in April 2008, the Facility required that we maintain a debt to total capitalization
ratio of less than or equal to 60%.
DCP Midstream Partners Credit Facilities with Financial Institutions On June 21, 2007, DCP
Partners entered into the Amended and Restated Credit Agreement that matures on June 21, 2012, or
the DCP Partners Credit Agreement, which replaced the existing credit agreement, and consists of a
total credit facility of $850 million, including a $790 million revolving credit facility and a $60
million term loan facility as of December 31, 2008. At December 31, 2008 DCP Partners had less than
$1 million of letters of credit outstanding under the DCP Partners Credit Agreement. As of
December 31, 2008 the available capacity under the revolving credit facility was $172 million. The
$172 million available capacity at December 31, 2008 is net of approximately $22 million
non-participation by Lehman Brothers as discussed below. Outstanding balances under the term loan
facility are fully collateralized by investments in high-grade securities, which are classified as
restricted investments in the accompanying consolidated balance sheet as of December 31, 2008.
During 2008, total outstanding indebtedness under the DCP Partners Credit Agreement ranged from
$630 million to $735 million. The weighted average total indebtedness outstanding under the DCP
Partners Credit Agreement was approximately $664 million for the year ended December 31, 2008.
Under the DCP Partners Credit Agreement, indebtedness under the revolving credit facility
bears interest at either: (1) the higher of Wachovia Banks prime rate or the federal funds rate
plus 0.50%; or (2) LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent
upon the leverage level or credit rating. The revolving credit facility incurs an annual facility
fee of 0.07% to 0.175% depending on the applicable leverage level or debt rating. This fee is paid
on drawn and undrawn portions of the revolving credit facility. The term loan facility bears
interest at a rate equal to; (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Banks prime rate
or the federal funds rate plus 0.50%.
The DCP Partners Credit Agreement requires DCP Partners to maintain a leverage ratio (the
ratio of consolidated indebtedness to consolidated EBITDA, in each case as is defined by the DCP
Partners Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than
three consecutive quarters (including the quarter in which such acquisition is consummated)
following the consummation of qualifying asset acquisitions in the midstream energy business of not
more than 5.5 to 1.0. The DCP Partners Credit Agreement also requires DCP Partners to maintain an
interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense, in each
case as is defined by the DCP Partners Credit Agreement) of greater than or equal to 2.5 to 1.0
determined as of the last day of each quarter for the four-quarter period ending on the date of
determination.
Lehman Brothers Commercial Bank, or Lehman Brothers, is a lender under the DCP Partners
Credit Agreement. Lehman Brothers has not funded its portion of DCP Partners borrowing requests
since its bankruptcy, and it is uncertain whether it will participate in future borrowing requests.
Accordingly, the availability of new borrowings under the DCP Partners Credit Agreement has been
reduced by approximately $22 million as of December 31, 2008. If Lehman Brothers elects not to
participate in the DCP Partners Credit Agreement, or does not transfer their commitment to another
commercial lender under the credit facility, the availability will be reduced by up to an
additional $3 million, for a total reduction of up to $25 million.
Other Agreements As of December 31, 2008, DCP Partners had an outstanding letter of credit
with a counterparty to their commodity derivative instruments of $10 million, which reduces the
amount of cash DCP Partners may be required to post as collateral. This letter of credit was issued
directly by a financial institution and does not reduce the available capacity under the DCP
Partners Credit Agreement.
Other Financing In March 2008, DCP Partners issued 4,250,000 common limited partner units at
$32.44 per unit, and received proceeds of approximately $132 million, net of offering costs.
22
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments
The impact of our derivative activity on our results of operations and financial position is
summarized below:
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
Interest rate derivative instruments: |
|
|
|
|
Losses reclassified from AOCI into earnings |
|
$ |
3 |
|
Commodity derivative activity: |
|
|
|
|
Unrealized gains from derivative activity |
|
$ |
194 |
|
Realized (losses) from derivative activity |
|
|
(93 |
) |
|
|
|
|
Total trading and marketing gains, net |
|
$ |
101 |
|
|
|
|
|
For the year ended December 31, 2008, no derivative gains or losses were reclassified from
AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to
certain forecasted transactions that are not probable of occurring.
Commodity Price Risk Our principal operations of gathering, processing, compression,
transportation and storage of natural gas, and the accompanying operations of fractionation,
transportation, gathering, treating, processing, storage and trading and marketing of NGLs create
commodity price risk exposure due to market fluctuations in commodity prices, primarily with
respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas
processing and other midstream assets, we have an inherent exposure to market variables and
commodity price risk. The amount and type of price risk is dependent on the underlying natural gas
contracts entered into to purchase and process natural gas. Risk is also dependent on the types and
mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported
or stored.
Energy Trading (Market) Risk Certain of our subsidiaries are engaged in the business of
trading energy related products and services, including managing purchase and sales portfolios,
storage contracts and facilities, and transportation commitments for products. These energy trading
operations are exposed to market variables and commodity price risk with respect to these products
and services, and we may enter into physical contracts and financial instruments with the objective
of realizing a positive margin from the purchase and sale of commodity-based instruments.
Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates,
therefore we are exposed to market risks related to changes in interest rates. We periodically use
interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include
(1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing
volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive
interest rates based on historical rates.
Credit Risk Our principal customers range from large, natural gas marketing services to
industrial end-users for our natural gas products and services, as well as large multi-national
petrochemical and refining companies, to small regional propane distributors for our NGL products
and services. Substantially all of our natural gas and NGL sales are made at market-based prices.
Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an
existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our
overall credit risk, in that these customers may be similarly affected by changes in economic,
regulatory or other factors. Where exposed to credit risk, we analyze the counterparties financial
condition prior to entering into an agreement, establish credit limits and monitor the
appropriateness of these limits on an ongoing basis. We may use various master agreements that
include language giving us the right to request collateral to mitigate credit exposure. The
collateral language provides for a counterparty to post cash or letters of credit for exposure in
excess of the established threshold. The threshold amount represents an open credit limit,
determined in accordance with our credit policy. The collateral language also provides that the
inability to post collateral is sufficient cause to terminate a contract and liquidate all
positions. In addition, our master agreements and our standard gas and NGL sales contracts contain
adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or
continue deliveries to the buyer after the buyer provides security for payment in a satisfactory
form.
23
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
As of December 31, 2008, we held cash deposits of $26 million included in other current
liabilities and letters of credit of $163 million from counterparties to secure their future
performance under financial or physical contracts. We had cash deposits with counterparties of $42
million, included in other current assets, to secure our obligations to provide future services or
to perform under financial contracts. As of December 31, 2008, DCP Partners had no cash collateral
posted with counterparties to their commodity derivative instruments. As of December 31, 2008, DCP
Partners had an outstanding letter of credit with a counterparty to its commodity derivative
instruments of $10 million. This letter of credit was issued directly by a financial institution
and does not reduce the available capacity under the DCP Partners Credit Agreement. This letter of
credit reduces the amount of cash DCP Partners may be required to post as collateral. Collateral
amounts held or posted may be fixed or may vary, depending on the value of the underlying
contracts, and could cover normal purchases and sales, trading and hedging contracts. In many
cases, we and our counterparties publicly disclose credit ratings, which may impact the amounts of
collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the
expiration of the contract term. These transactions are generally subject to specific credit
provisions within the contracts that would allow the seller, at its discretion, to suspend
deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security
for payment satisfactory to the seller.
Commodity Derivative Activity Our operations of gathering, processing, and transporting
natural gas, and the related operations of transporting and marketing of NGLs create commodity
price risk due to market fluctuations in commodity prices, primarily with respect to the prices of
NGLs, natural gas and crude oil.
We manage our commodity derivative activities in accordance with our risk management policy,
which limits exposure to market risk and requires regular reporting to management of potential
financial exposure.
Commodity Cash Flow Protection Activities DCP Partners uses natural gas and crude oil swaps
and option contracts to mitigate the risk of market fluctuations in the price of NGLs, natural gas
and condensate. Prior to July 1, 2007, the effective portion of the change in fair value of a
derivative designated as a cash flow hedge was accumulated in AOCI. During the period in which the
hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were
reclassified to the consolidated statements of operations and comprehensive income in the same
accounts as the item being hedged.
Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for
derivatives associated with managing DCP Partners commodity price risk. As a result, the remaining
net loss deferred in AOCI at that time is being reclassified to sales of natural gas and petroleum
products through December 2011, as the derivative transactions impact earnings. Subsequent to July
1, 2007, the changes in fair value of these financial derivatives are included in trading and
marketing gains and losses in the consolidated statements of operations and comprehensive income.
The agreements are with major financial institutions, which are expected to fully perform under the
terms of the agreements.
As of December 31, 2008, DCP Partners has mitigated a portion of their expected natural gas
and condensate commodity price risk associated with the equity volumes from their gathering and
processing operations through 2013 with natural gas, NGL and crude oil derivatives.
Commodity Cash Flow Hedges During 2008, we executed a series of derivative financial
instruments, which have been designated as cash flow hedges of the price risk associated with
forecasted purchases of natural gas in 2010. For the year ended December 31, 2008, amounts
recognized as comprehensive income in the consolidated statements of operations and comprehensive
income for changes in the fair value of these hedge instruments were not significant. Amounts
recognized for the effects of any ineffectiveness were also not significant. No amounts were
reclassified to the consolidated statements of operations and comprehensive income as a result of
settlements and no derivative gains or losses were reclassified from AOCI to current period
earnings as a result of the change in probability of forecasted transactions occurring. The
deferred balance in AOCI was a loss of approximately $1 million at December 31, 2008. Amounts
expected to be reclassified from AOCI into earnings during the next 12 months are not significant.
Due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to
change prior to its reclassification into earnings.
Commodity Fair Value Hedges Historically, we used fair value hedges to mitigate risk to
changes in the fair value of an asset or a liability (or an identified portion thereof) that is
attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and
market locks (fixed price gas sales) to reduce our cash flow exposure to fixed price risk via
swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index
based).
24
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Normal Purchases and Normal Sales If a contract qualifies and is designated as a normal
purchase or normal sale, no recognition of the contracts fair value in the consolidated financial
statements is required until the associated delivery period impacts earnings. We have applied this
accounting election for contracts involving the purchase or sale of commodities in future periods,
as well as select operating expense contracts.
Commodity Derivatives Trading and Marketing Our trading and marketing program is designed
to realize margins related to fluctuations in commodity prices and basis differentials, and to
maximize the value of certain storage and transportation assets. Certain of our subsidiaries are
engaged in the business of trading energy related products and services including managing purchase
and sales portfolios, storage contracts and facilities, and transportation commitments for
products. These energy trading operations are exposed to market variables and commodity price risk
with respect to these products and services, and may enter into physical contracts and financial
instruments with the objective of realizing a positive margin from the purchase and sale of
commodity-based instruments. We manage our trading and marketing portfolio with strict policies,
which limit exposure to market risk, and require daily reporting to management of potential
financial exposure. These policies include statistical risk tolerance limits using historical price
movements to calculate daily value at risk.
Interest Rate Cash Flow Hedges DCP Partners mitigates a portion of their interest rate risk
with interest rate swaps, which reduce the exposure to market rate fluctuations by converting
variable interest rates to fixed interest rates. These interest rate swaps convert the interest
rate associated with an aggregate of $575 million of the variable rate exposure to a fixed rate
obligation. All interest rate swap agreements have been designated as cash flow hedges, and
effectiveness is determined by matching the principal balance and terms with that of the specified
obligation. The effective portions of changes in fair value are recognized in AOCI in the
consolidated balance sheet. As of December 31, 2008, $5 million of deferred net losses on
derivative instruments in AOCI are expected to be reclassified into earnings during the next 12
months as the hedged transactions impact earnings however, due to the volatility of the interest
rate markets, the corresponding value in AOCI is subject to change prior to its reclassification
into earnings. Ineffective portions of changes in fair value are recognized in earnings. Under the
terms of the interest rate swap agreements, we pay fixed rates ranging from 2.26% to 5.19% and
receive interest payments based on the three-month LIBOR. The differences to be paid or received
under the interest rate swap agreements are recognized as an adjustment to interest expense. The
agreements are with major financial institutions, which are expected to fully perform under the
terms of the agreements.
Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury
locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of
debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred
in AOCI and amortized against interest expense over the life of the respective debt. The amount
amortized to interest expense during the year ended December 31, 2008 was $1 million. The deferred
balance was a loss of $4 million at December 31, 2008. Approximately $1 million of deferred net
losses related to these instruments in AOCI are expected to be reclassified into earnings during
the next 12 months as the underlying hedged interest expense transaction occurs.
Interest Rate Fair Value Hedges We entered into interest rate swaps to convert $100 million
of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair
value hedges were at a floating rate based on six-month LIBOR, which was re-priced semiannually
through 2030. The swaps met conditions that permitted the assumption of no ineffectiveness. As
such, for the life of the swaps no ineffectiveness was recognized. These swaps were terminated in
December 2008 and we received cash of approximately $36 million net of a $7 million transaction
fee. The remaining $43 million change in fair value of the underlying debt will be amortized as a
reduction to interest expense through 2030.
13. Non-Controlling Interest
Non-controlling interest represents the ownership interests of third-party entities in net
assets of various equity method investments in consolidated affiliates, including ownership
interest of DCP Partners public unitholders in net assets of DCP Partners through DCP Partners
publicly traded common units, and in net assets of DCP East Texas Holdings, LLC, of which DCP
Partners acquired a 25% equity interest in July 2007 as well as Collbran Valley Gas Gathering,
which was acquired by DCP Partners in conjunction with the MEG acquisition in August 2007 and has a
30% non-controlling interest. Jackson Pipeline Company, LP was acquired by DCP Partners in
conjunction with the MPP acquisition in October 2008 and has a 25% non-controlling interest. For
financial reporting purposes, the assets and liabilities of these entities are consolidated with
those of our own, with any third party and affiliate investors interest in our consolidated
balance sheet amounts shown as non-controlling interest. Distributions to and contributions from
non-controlling interests represent cash payments and cash contributions, respectively, from such
third-party and affiliate investors.
25
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
14. Equity-Based Compensation
We recorded equity-based compensation benefit as follows, the components of which
are further described below:
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2008 |
|
|
|
(millions) |
|
DCP Partners Long-Term Incentive Plan (DCP Partners Plan) |
|
$ |
(1 |
) |
|
|
|
|
Duke Energy 1998 Plan and Spectra Energy Long-Term Incentive Plan |
|
|
(1 |
) |
|
|
|
|
Total |
|
$ |
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized |
|
|
|
|
|
|
|
|
|
|
|
|
Compensation |
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Expense at |
|
|
|
|
|
Average |
|
|
Vesting |
|
December 31, |
|
Estimated |
|
Remaining |
|
|
Period |
|
2008 |
|
Forfeiture |
|
Vesting |
|
|
(years) |
|
(millions) |
|
Rate |
|
(years) |
DCP Midstreams 2006 Plan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relative Performance Units (RPUs) |
|
|
8 |
|
|
$ |
|
|
|
|
72 |
%(a) |
|
|
5 |
|
Strategic Performance Units (SPUs) |
|
|
3 |
|
|
$ |
2 |
|
|
|
22 |
%(a) |
|
|
1 |
|
Phantom Units |
|
|
5 |
|
|
$ |
2 |
|
|
|
23 |
%(a) |
|
|
2 |
|
DCP Partners Phantom Units |
|
|
3 |
|
|
$ |
|
|
|
|
22 |
%(a) |
|
|
|
|
DCP Partners Plan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Units |
|
|
3 |
|
|
$ |
|
|
|
|
50 |
% |
|
|
1 |
|
Phantom Units |
|
|
0.5/3 |
|
|
$ |
|
|
|
|
0 |
% |
|
|
|
|
Restricted Phantom Units |
|
|
3 |
|
|
$ |
|
|
|
|
50 |
% |
|
|
2 |
|
Duke Energys 1998 Plan and Spectra
Energys 2007 LTIP Plan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options (no activity in 2007 or 2008) |
|
|
0-10 |
|
|
$ |
|
|
|
NA |
|
|
|
|
|
Stock Based Performance Awards |
|
|
3 |
|
|
$ |
|
|
|
|
6 |
% |
|
|
|
|
Phantom Awards |
|
|
1-5 |
|
|
$ |
|
|
|
|
6 |
% |
|
|
1 |
|
Other Stock Awards |
|
|
1-5 |
|
|
$ |
|
|
|
NA |
|
|
|
|
|
|
|
|
(a) |
|
Weighted-average estimated forfeiture rate |
DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan Under our 2006 Long Term Incentive
Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides
for the grant of Relative Performance Units, or RPUs, Strategic Performance Units, or SPUs, and
Phantom Units. The RPUs, SPUs and Phantom Units consist of a notional unit based on the value of
common shares or units of ConocoPhillips, Duke Energy, Spectra Energy and DCP Partners. The
weighting varies depending on when the units were granted. The DCP Partners Phantom Units
constitute a notional unit equal to the fair value of DCP Partners common units. Each award
provides for the grant of dividend or distribution equivalent rights, or DERs. The 2006 Plan is
administered by the compensation committee of our board of directors. We first granted awards under
the 2006 Plan during the second quarter of 2006. All awards are subject to cliff vesting.
Relative Performance Units The number of RPUs that will ultimately vest range from 0% to
200% of the outstanding RPUs, depending on the achievement of specified performance targets over a
three year period ending in January 2009 and 2010, respectively, for units granted in 2006 and
2007. The final performance payout is determined by the compensation committee of our board of
directors. After the performance period, vesting occurs over five years, at the end of which the
value is based on the participants investment elections during the deferral period. The DERs will
be paid in cash at the end of the performance period. The following tables presents information
related to RPUs:
26
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
|
|
Units |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
62,167 |
|
|
$ |
43.41 |
|
|
|
|
|
Forfeited |
|
|
(5,850 |
) |
|
$ |
43.36 |
|
|
|
|
|
Vested or paid in cash |
|
|
(3,047 |
) |
|
$ |
42.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
53,270 |
|
|
$ |
43.44 |
|
|
$ |
31.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
26,892 |
|
|
$ |
43.36 |
|
|
$ |
32.06 |
|
Strategic Performance Units The number of SPUs that will ultimately vest range from 0% to
200% of the outstanding SPUs, depending on the achievement of specified performance targets over a
three year period ending on December 31, 2008, 2009 and 2010, respectively, for units granted in
2006, 2007 and 2008. The final performance payout is determined by the compensation committee of
our board of directors. The DERs will be paid in cash at the end of the performance period. The
following tables presents information related to SPUs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
|
|
Units |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
140,019 |
|
|
$ |
43.49 |
|
|
|
|
|
Granted |
|
|
112,930 |
|
|
$ |
35.49 |
|
|
|
|
|
Forfeited |
|
|
(14,617 |
) |
|
$ |
41.86 |
|
|
|
|
|
Vested or paid in cash |
|
|
(3,047 |
) |
|
$ |
42.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
235,285 |
|
|
$ |
39.76 |
|
|
$ |
26.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
166,879 |
|
|
$ |
39.27 |
|
|
$ |
26.46 |
|
The estimate of RPUs and SPUs that are expected to vest is based on highly subjective
assumptions that could potentially change over time, including the expected forfeiture rate and
achievement of performance targets. Therefore the amounts of unrecognized compensation expense
noted above does not necessarily represent the value that will ultimately be realized in our
consolidated statements of operations and comprehensive income.
27
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Phantom Units The DERs are paid quarterly in arrears. The following table presents
information related to Phantom Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
|
|
Units |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
33,800 |
|
|
$ |
43.57 |
|
|
|
|
|
Granted |
|
|
112,930 |
|
|
$ |
35.49 |
|
|
|
|
|
Forfeited |
|
|
(5,270 |
) |
|
$ |
39.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
141,460 |
|
|
$ |
37.39 |
|
|
$ |
23.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
115,334 |
|
|
$ |
37.44 |
|
|
$ |
23.80 |
|
DCP Partners Phantom Units The DERs are paid quarterly in arrears. The following table
presents information related to the DCP Partners Phantom Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
Weighted- |
|
Measurement |
|
|
|
|
|
|
Average Price |
|
Date Price Per |
|
|
Units |
|
Per Unit |
|
Unit |
Outstanding at January 1, 2008 |
|
|
51,750 |
|
|
$ |
34.33 |
|
|
|
|
|
Forfeited |
|
|
(2,750 |
) |
|
$ |
51.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
49,000 |
|
|
$ |
33.39 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
48,750 |
|
|
$ |
33.33 |
|
|
$ |
9.40 |
|
DCP Partners Long-Term Incentive Plan, or DCP Partners Plan Under DCP Partners Long Term
Incentive Plan, or DCP Partners Plan, which was adopted by DCP Midstream GP, LLC, equity
instruments may be granted to key employees, consultants and directors of DCP Midstream GP, LLC and
its affiliates who perform services for DCP Partners. The DCP Partners Plan provides for the grant
of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with
respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs.
Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered
pursuant to awards under the DCP Partners Plan. Awards that are canceled, forfeited or withheld to
satisfy DCP Midstream GP, LLCs tax withholding obligations are available for delivery pursuant to
other awards. The DCP Partners Plan is administered by the compensation committee of DCP Midstream
GP, LLCs board of directors. All awards are subject to cliff vesting, with the exception of the
Phantom Units issued to the directors in conjunction with the initial public offering, which are
subject to graded vesting provisions.
Awards granted to directors and awards granted to employees in 2008 are accounted for as
equity-based awards; all other awards are accounted for as liability awards.
28
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Performance Units The number of Performance Units that will ultimately vest range from 0% to
200% of the outstanding Performance Units, depending on the achievement of specified performance
targets over three year performance periods. The final performance percentage payout is determined
by the compensation committee of DCP Partners board of directors. The DERs will be paid in cash at
the end of the performance period. The following table presents information related to the
Performance Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
Measurement |
|
|
|
|
|
|
Weighted- |
|
Date |
|
|
|
|
|
|
Average Price |
|
Price |
|
|
Units |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
46,960 |
|
|
$ |
32.93 |
|
|
|
|
|
Granted |
|
|
17,085 |
|
|
$ |
33.85 |
|
|
|
|
|
Forfeited |
|
|
(12,025 |
) |
|
$ |
32.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
52,020 |
|
|
$ |
33.35 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest (a) |
|
|
45,350 |
|
|
$ |
31.70 |
|
|
$ |
9.40 |
|
|
|
|
(a) |
|
Based on our December 31, 2008 estimated achievement of specified performance
targets, the performance target for units that are expected to vest for units
granted in 2008 is 100%, for units granted in 2007 is 102% and for units granted in
2006 is 150%. The estimated forfeiture rate for units granted in 2008 and 2007 is
50%, and for units granted in 2006 is 0%. |
The estimate of Performance Units that are expected to vest is based on highly subjective
assumptions that could potentially change over time, including the expected forfeiture rate and
achievement of performance targets. Therefore the amount of unrecognized compensation expense noted
above does not necessarily represent the value that will ultimately be realized in our consolidated
statements of operations and comprehensive income.
Phantom Units In conjunction with their initial public offering, in January 2006 DCP
Partners awarded Phantom Units to key employees, and to directors who are not officers or employees
of DCP Midstream GP, LLC, or its affiliates who perform services for DCP Partners. The remaining
Phantom Units outstanding at December 31, 2008 vested on January 3, 2009.
In 2007, DCP Partners granted 4,500 Phantom Units pursuant to the DCP Partners Plan, to
directors who are not officers or employees of affiliates of DCP Midstream as part of their annual
director fees for 2007. Of these Phantom Units, 4,000 units vested during 2007 and 500 units vested
during 2008.
In 2008, DCP Partners granted 4,000 Phantom Units, pursuant to the LTIP, to directors who are
not officers or employees of affiliates of DCP Midstream as part of their annual director fees in
2008. All of these units vested during 2008.
The DERs are paid quarterly in arrears.
The following table presents information related to the Phantom Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
Measurement |
|
|
|
|
|
|
Weighted- |
|
Date |
|
|
|
|
|
|
Average Price |
|
Price |
|
|
Units |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
20,199 |
|
|
$ |
24.56 |
|
|
|
|
|
Granted |
|
|
4,000 |
|
|
$ |
35.88 |
|
|
|
|
|
Forfeited |
|
|
(4,000 |
) |
|
$ |
24.05 |
|
|
|
|
|
Vested or paid in cash |
|
|
(6,501 |
) |
|
$ |
32.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
13,698 |
|
|
$ |
24.05 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
13,698 |
|
|
$ |
24.05 |
|
|
$ |
9.40 |
|
The estimate of Phantom Units that are expected to vest is based on highly subjective
assumptions that could potentially change over time, including the expected forfeiture rate.
29
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
Restricted Phantom Units DCP Midstream Partners General Partners board of directors
awarded restricted phantom LPUs, or RPUs, to key employees under the LTIP. The RPUs are expected to
vest on December 31, 2011. The DERs are paid quarterly in arrears. The following table presents
information related to the RPUs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
Weighted- |
|
Measurement |
|
|
|
|
|
|
Average Price |
|
Date Price |
|
|
Units |
|
per Unit |
|
per Unit |
Outstanding at January 1, 2008 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
Granted |
|
|
17,085 |
|
|
$ |
33.85 |
|
|
|
|
|
Forfeited |
|
|
(2,395 |
) |
|
$ |
35.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
14,690 |
|
|
$ |
33.52 |
|
|
$ |
9.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
8,544 |
|
|
$ |
33.85 |
|
|
$ |
9.40 |
|
The estimate of RPUs that are expected to vest is based on highly subjective assumptions that
could potentially change over time, including the expected forfeiture rate.
All awards issued under the 2006 Plan and the DCP Partners Plan are intended to be settled in
cash at each reporting period or units upon vesting. Compensation expense is recognized ratably
over each vesting period, and will be remeasured quarterly for all awards outstanding until the
units are vested. The fair value of all awards is determined based on the closing price of the
relevant underlying securities at each measurement date.
Duke Energy 1998 Plan and Spectra Energy 2007 Long-Term Incentive Plan Under the Duke Energy
1998 Plan, or the 1998 Plan, Duke Energy granted certain of our key employees stock options,
stock-based performance awards, phantom stock awards and other stock awards to be settled in shares
of Duke Energys common stock, or the Stock-Based Awards. Upon execution of the 50-50 Transaction
in July 2005, our employees incurred a change in status from Duke Energy employees to
non-employees. As a result, we began accounting for these awards using the fair value method. No
awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.
In connection with the Spectra spin, one replacement Duke Energy Stock-Based Award and
one-half Spectra Energy Stock-Based Award were distributed to each holder of Duke Energy
Stock-Based Awards for each award held at the time of the Spectra spin. Substantially all converted
Stock-Based Awards are subject to the terms and conditions applicable to the original Duke Energy
Stock-Based Awards. The Spectra Energy Stock-Based Awards resulting from the conversion are
considered to have been issued under the Spectra Energy 2007 Long-Term Incentive Plan, or the
Spectra Energy 2007 LTIP.
The Spectra Energy 2007 LTIP provides for the granting of stock options, restricted stock
awards and units, unrestricted stock awards and units, and other equity-based awards, to employees
and other key individuals who perform services for Spectra Energy. A maximum of 30 million shares
of common stock may be awarded under the Spectra Energy 2007 LTIP. Options granted under the
Spectra Energy 2007 LTIP are issued with exercise prices equal to the fair market value of Spectra
Energy common stock on the grant date, have ten year terms, and vest immediately or over terms not
to exceed five years. Compensation expense related to stock options is recognized over the
requisite service period. The requisite service period for stock options is the same as the vesting
period, with the exception of retirement eligible employees, who have shorter requisite service
periods ending when the employees become retirement eligible. Restricted, performance and phantom
stock awards granted under the Spectra Energy 2007 LTIP typically become 100% vested on the
three-year anniversary of the grant date. The fair value of the awards granted is measured based on
the fair market value of the shares on the date of grant, and the related compensation expense is
recognized over the requisite service period which is the same as the vesting period.
Stock Options Under the 1998 Plan, the exercise price of each option granted could not be
less than the market price of Duke Energys common stock on the date of grant. Effective July 1,
2005, these options were accounted using the fair value method. As a result, compensation expense
subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock
options at each reporting date until vesting.
30
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
The following table shows information regarding options to purchase Duke Energys common stock
granted to our employees, reflecting shares outstanding as impacted by the conversion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
Weighted- |
|
Remaining |
|
Aggregate |
|
|
|
|
|
|
Average |
|
Life |
|
Intrinsic Value |
|
|
Shares |
|
Exercise Price |
|
(years) |
|
(millions) |
Outstanding at January 1, 2008 |
|
|
1,815,956 |
|
|
$ |
17.89 |
|
|
|
3.2 |
|
|
|
|
|
Exercised |
|
|
(151,480 |
) |
|
$ |
13.45 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(106,889 |
) |
|
$ |
19.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
1,557,587 |
|
|
$ |
18.19 |
|
|
|
2.4 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2008 |
|
|
1,557,587 |
|
|
$ |
18.19 |
|
|
|
2.4 |
|
|
$ |
2 |
|
The total intrinsic value of options exercised during the year ended December 31, 2008 was
approximately $1 million.
The following table shows information regarding options to purchase Spectra Energys common
stock granted to our employees, reflecting shares outstanding as impacted by the conversion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Remaining |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Life |
|
|
Intrinsic Value |
|
|
|
Shares |
|
|
Exercise Price |
|
|
(years) |
|
|
(millions) |
|
Outstanding at January 1, 2008 |
|
|
937,248 |
|
|
$ |
26.80 |
|
|
|
3.2 |
|
|
|
|
|
Exercised |
|
|
(68,869 |
) |
|
$ |
18.91 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(72,400 |
) |
|
$ |
28.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
795,979 |
|
|
$ |
27.36 |
|
|
|
2.4 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2008 |
|
|
795,979 |
|
|
$ |
27.36 |
|
|
|
2.4 |
|
|
$ |
1 |
|
The total intrinsic value of options exercised during the year ended December 31, 2008 was
approximately $1 million.
Stock-Based Performance Awards There were no stock-based performance awards granted during
the year ended December 31, 2008.
The following tables summarize information about stock-based performance awards activity,
reflecting shares outstanding as impacted by the conversion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
Duke Energy 1998 Plan |
|
Shares |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
173,365 |
|
|
$ |
15.58 |
|
|
|
|
|
Vested |
|
|
(83,762 |
) |
|
$ |
15.39 |
|
|
|
|
|
Forfeited |
|
|
(59,663 |
) |
|
$ |
15.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
29,940 |
|
|
$ |
16.50 |
|
|
$ |
15.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
28,200 |
|
|
$ |
16.50 |
|
|
$ |
15.01 |
|
31
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
Spectra Energy 2007 LTIP |
|
Shares |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
86,683 |
|
|
$ |
23.54 |
|
|
|
|
|
Vested |
|
|
(41,884 |
) |
|
$ |
23.25 |
|
|
|
|
|
Forfeited |
|
|
(29,829 |
) |
|
$ |
23.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
14,970 |
|
|
$ |
24.94 |
|
|
$ |
15.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
14,009 |
|
|
$ |
24.94 |
|
|
$ |
15.74 |
|
The total fair value of the performance stock awards that vested during the year ended
December 31, 2008 was approximately $2 million. No awards were granted during the year ended
December 31, 2008.
Phantom Stock Awards There were no phantom stock awards granted during the year ended
December 31, 2008.
The following tables summarize information about phantom stock awards activity, reflecting
shares outstanding as impacted by the conversion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
Duke Energy 1998 Plan |
|
Shares |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
77,210 |
|
|
$ |
15.62 |
|
|
|
|
|
Vested |
|
|
(24,419 |
) |
|
$ |
15.57 |
|
|
|
|
|
Forfeited |
|
|
(3,287 |
) |
|
$ |
15.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
49,504 |
|
|
$ |
15.66 |
|
|
$ |
15.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
46,627 |
|
|
$ |
15.66 |
|
|
$ |
15.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measurement |
|
|
|
|
|
|
Grant Date |
|
Date |
|
|
|
|
|
|
Weighted- |
|
Weighted- |
|
|
|
|
|
|
Average Price |
|
Average Price |
Spectra Energy 2007 LTIP |
|
Shares |
|
Per Unit |
|
Per Unit |
Outstanding at January 1, 2008 |
|
|
38,605 |
|
|
$ |
23.60 |
|
|
|
|
|
Vested |
|
|
(12,209 |
) |
|
$ |
23.53 |
|
|
|
|
|
Forfeited |
|
|
(1,644 |
) |
|
$ |
23.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
24,752 |
|
|
$ |
23.66 |
|
|
$ |
15.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest |
|
|
23,163 |
|
|
$ |
23.66 |
|
|
$ |
15.74 |
|
The total fair value of the phantom stock awards that vested during the year ended December
31, 2008 was approximately $1 million. No awards were granted during the year ended December 31,
2008.
15. Benefits
All Company employees who are 18 years old and work at least 20 hours per week are eligible
for participation in our 401(k) and retirement plan, to which we contributed a range of 4% to 7% of
each eligible employees qualified earnings to the retirement plan, based on years of service.
Additionally, we match employees contributions in the 401(k) plan up to 6% of qualified earnings.
We offer certain eligible executives the opportunity to participate in DCP Midstream LPs
Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current
compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The
plan also has make-whole provisions for plan participants who may otherwise be limited in the
amount that we can contribute to the 401(k) plan on the participants behalf. All amounts
contributed to or earned by the plans investments are
32
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
held in a trust account for the benefit of the participants. The trust and the liability to the
participants are part of our general assets and liabilities, respectively.
16. Income Taxes
We are structured as a limited liability company, which is a pass-through entity for United
States income tax purposes. We own a corporation that files its own federal, foreign and state
corporate income tax returns. The income tax (benefit) expense related to this corporation is
included in our income tax (benefit) expense, along with state and local taxes of the limited
liability company and other subsidiaries.
The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned
to Texas. Accordingly, we have recorded current tax expense for the Texas margin tax beginning in
2007. During 2008, we acquired properties in Michigan, which imposes a business tax of 0.8% on
gross receipts and 4.95% of Michigan taxable income. The sum of gross receipts and income tax is
subject to a tax surcharge of 21.99%. Michigan provides tax credits that may reduce our final
income tax liability.
The Company has a net long-term deferred tax asset of approximately $3 million at December 31,
2008, which is included in other long-term assets on the consolidated balance sheet. The deferred
tax asset is comprised of differences between the financial statement carrying amount and the tax
basis of property, plant and equipment ($18 million liability), investments in consolidated
affiliates ($10 million asset), and net operating loss ($11 million asset). The net operating
losses begin expiring in 2021, which we expect to fully utilize.
17. Commitments and Contingent Liabilities
Litigation The midstream industry has seen a number of class action lawsuits involving
royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these
types of cases before, they were typically brought by a single plaintiff or small group of
plaintiffs. A number of these cases are now being brought as class actions. We are currently named
as defendants in some of these cases. Management believes we have meritorious defenses to these
cases and, therefore, will continue to defend them vigorously. These class actions, however, can be
costly and time consuming to defend. We are also a party to various legal, administrative and
regulatory proceedings that have arisen in the ordinary course of our business.
In March 2008, after receiving regulatory approval, we finalized settlement of a lawsuit
alleging migration of acid gas from a storage formation into a third-party producing formation. We
obtained the land and the rights to the producing formation. This matter did not have a material
adverse effect upon our consolidated results of operations, financial position or cash flows.
In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our
subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court,
in Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP
Partners Minden processing plant that dates back to August 2000. El Paso claims damages, including
interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims
under our commercial contract.
Management currently believes that these matters, taken as a whole, and after consideration of
amounts accrued, insurance coverage and other indemnification arrangements, will not have a
material adverse effect upon our consolidated results of operations, financial position or cash
flows.
General Insurance Midstreams insurance coverage is carried with an affiliate of
ConocoPhillips and third-party insurers. Midstreams insurance coverage includes: (1) general
liability insurance covering third-party exposures; (2) statutory workers compensation insurance;
(3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess
liability insurance above the established primary limits for general liability and automobile
liability insurance; (5) property insurance, which covers the replacement value of all real and
personal property and includes business interruption/extra expense; and (6) directors and officers
insurance covering our directors and officers for acts related to our business activities. All
coverage is subject to certain limits and deductibles, the terms and conditions of which are common
for companies with similar types of operations.
Environmental The operation of pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs and other products is subject to
stringent and complex laws and regulations pertaining to health, safety and the environment. As an
owner or operator of these facilities, we must comply with United States laws and regulations at
the federal, state
33
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED BALANCE SHEET Continued
AS OF DECEMBER 31, 2008
and local levels that relate to air and water quality, hazardous and solid waste storage,
management, transportation and disposal, and other environmental matters. The cost of planning,
designing, constructing and operating pipelines, plants, and other facilities must incorporate
compliance with environmental laws and regulations and safety standards. Failure to comply with
these laws and regulations may trigger a variety of administrative, civil and potentially criminal
enforcement measures, including citizen suits, which can include the assessment of monetary
penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on
operation. Management believes that, based on currently known information, compliance with these
laws and regulations will not have a material adverse effect on our consolidated results of
operations, financial position or cash flows.
On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to
us that listed air quality violations during the previous five years at three of our owned or
operated facilities in New Mexico. The orders alleged a number of violations related to excess
emissions beginning January 2001, and further required us to install flares for smokeless
operations and to use the flares only for emergency purposes. On April 17, 2008, we signed a
settlement agreement with the New Mexico Environment Department that resolved all alleged
violations through the date of the settlement agreement. Under the terms of the settlement
agreement, we paid approximately $2 million in civil penalties and agreed to fund $59 million in
facility upgrades at three of our gas plants through April 2011.
We utilize assets under operating leases in several areas of operations. Rental expense for
leases with escalation clauses is recognized on a straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in the year indicated are as
follows:
|
|
|
|
|
Minimum Rental Payments |
|
(millions) |
|
2009 |
|
$ |
28 |
|
2010 |
|
|
25 |
|
2011 |
|
|
24 |
|
2012 |
|
|
22 |
|
2013 |
|
|
20 |
|
Thereafter |
|
|
23 |
|
|
|
|
|
Total payments |
|
$ |
142 |
|
|
|
|
|
18. Guarantees and Indemnifications
We periodically enter into agreements for the acquisition or divestiture of assets. These
agreements contain indemnification provisions that may provide indemnity for environmental, tax,
employment, outstanding litigation, breaches of representations, warranties and covenants, or other
liabilities related to the assets being acquired or divested. Claims may be made by third parties
under these indemnification agreements for various periods of time depending on the nature of the
claim. The effective periods on these indemnification provisions generally have terms of one to
five years, although some are longer. Our maximum potential exposure under these indemnification
agreements can vary depending on the nature of the claim and the particular transaction. We are
unable to estimate the total maximum potential amount of future payments under indemnification
agreements due to several factors, including uncertainty as to whether claims will be made under
these indemnities.
19. Subsequent Events
In February 2009, we announced that our East Texas natural gas processing complex and residue
natural gas delivery system, known as the Carthage Hub, have been temporarily shut in following an
explosion and fire that occurred when a nearby third party owned pipeline outside of our property
line ruptured. We do not expect a material impact on our consolidated results of operations, cash
flows or financial position as a result of this event.
In February 2009, the remaining 3,571,429 DCP Partners subordinated units were converted into
common units following the completion of the subordination period and satisfactory completion of
all subordination period tests contained in the DCP Partners partnership agreement.
On January 27, 2009, the board of directors of the DCP Partners general partner declared a
quarterly distribution of $0.60 per unit, payable on February 13, 2009 to unitholders of record on
February 6, 2009.
34