SEC Filing | DCP Midstream, LP

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Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2009

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-32678

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware		03-0567133
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

370 17th Street, Suite 2775 Denver, Colorado		80202 (Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-633-2900

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class:		Name of Each Exchange on Which Registered:
Common Units Representing Limited Partner Interests		New York Stock Exchange

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 þ No ¨

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 ¨ 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 ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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 registrant’s 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. þ

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act. (Check one):


Large accelerated filer ¨		Accelerated filer þ		Non-accelerated filer ¨		Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

The aggregate market value of common limited partner units held by non-affiliates of the registrant on June 30, 2009, was approximately $429,482,000. The aggregate market value was computed by reference to the last sale price of the registrant’s common units on the New York Stock Exchange on June 30, 2009.

As of March 9, 2010, there were outstanding 34,608,183 common limited partner units.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

DCP MIDSTREAM PARTNERS, LP

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS


Item		Page

PART I.

1.	Business	2

1A.	Risk Factors	24

1B.	Unresolved Staff Comments	45

2.	Properties	45

3.	Legal Proceedings	46

4.	Reserved	46

PART II.

5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Units	47

6.	Selected Financial Data	48

7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51

7A.	Quantitative and Qualitative Disclosures about Market Risk	84

8.	Financial Statements and Supplementary Data	90

9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	145

9A.	Controls and Procedures	145

9B.	Other Information	147

PART III.

10.	Directors, Executive Officers and Corporate Governance	147

11.	Executive Compensation	152

12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	164

13.	Certain Relationships and Related Transactions, and Director Independence	165

14.	Principal Accounting Fees and Services	169

PART IV.

15.	Exhibits and Financial Statement Schedules	171

Signatures		187

Exhibit Index		189

GLOSSARY OF TERMS

The following is a list of certain industry terms used throughout this report:



Bbl		barrel

Bbls/d		barrels per day

BBtu/d		one billion Btus per day

Bcf/d		one billion cubic feet per day

Btu		British thermal unit, a measurement of energy

Fractionation		the process by which natural gas liquids are separated into individual components

Frac spread		price differences, measured in energy units, between equivalent amounts of natural gas and NGLs

MBbls		one thousand barrels

MBbls/d		one thousand barrels per day

MMBtu		one million Btus

MMBtu/d		one million Btus per day

MMcf		one million cubic feet

MMcf/d		one million cubic feet per day

MMscf		one million standard cubic feet

NGLs		natural gas liquids

Tcf		one trillion cubic feet

Throughput		the volume of product transported or passing through a pipeline or other facility

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:

•

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 and producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

•

general economic, market and business conditions;

•

the level and success of natural gas drilling around our assets, the level and quality of gas production volumes around our assets and our ability to connect supplies to our gathering and processing systems in light of competition;

•

our ability to grow through acquisitions, contributions from affiliates, or organic growth projects, and the successful integration and future performance of such assets;

•

our ability to access the debt and equity markets, which will depend on general market conditions, inflation rates, 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, our ability to comply with the covenants to our credit agreement, and our ability to maintain our credit rating;

•

our ability to purchase propane from our principal suppliers for our wholesale propane logistics business;

•

our ability to construct facilities in a timely fashion, which is partially dependent on obtaining required construction, 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;

•

the creditworthiness of counterparties to our transactions;

•

weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company owned and third-party-owned infrastructure;

•

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment, including climate change legislation, or the increased regulation of our industry;

•

our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of the insurance to cover our losses;

•

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

•

the amount of collateral we may be required to post from time to time in our transactions.

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.

Item 1.

Business

OUR PARTNERSHIP

DCP Midstream Partners, LP along with its consolidated subsidiaries, or we, us, our, or the partnership, is a Delaware master 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, storing and selling natural gas; transporting, storing and selling propane in wholesale markets; and producing, fractionating, 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 geographic location and type of our assets for all segments is set forth below. Additional maps detailing the individual assets can be found on our website at www.dcppartners.com. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report. For more information on our segments, see the “Our Operating Segments” discussion below.

LOGO

OVERVIEW AND STRATEGIES

Our Business Strategies

Our primary business objectives are to have sustained company profitability, a strong balance sheet and 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 new volumes to enhance utilization, improve operating efficiencies and capture marketing opportunities when available. Our facilities, terminals and 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 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 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.

Our Competitive Strengths

We believe that we are well positioned to execute our business strategies and achieve one of our primary business objectives 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), and one of the largest producers and 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 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.

We believe we are an important growth vehicle for DCP Midstream, LLC to pursue the acquisition, expansion, and organic construction of midstream natural gas, wholesale propane, NGL and other complementary energy businesses and assets. DCP Midstream, LLC has also provided us with growth opportunities through acquisitions directly from it. We expect to have future opportunities to make additional acquisitions directly from DCP 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 believe we have strong commercial relationships throughout the energy industry and access to DCP Midstream, LLC’s 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, our incentive distribution rights and an approximately 34% 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 govern our relationship with them regarding the operation of many of our assets, as well as certain reimbursement and indemnification matters.

Strategically located assets. Our assets are strategically located in areas that have 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 Colorado, Louisiana, Michigan, Oklahoma, Texas, 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 Colorado, Kansas, Louisiana and Texas 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 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 2014 with fixed price natural gas, NGL and crude oil swaps.

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 source and logistics capabilities 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 include 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.

Midstream Natural Gas Industry Overview

General

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, storing and selling of natural gas, and the production, transporting and selling of NGLs.

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.

LOGO

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 deplete, it becomes increasingly difficult to deliver the remaining lower pressure production from the well against the prevailing gathering system pressures. 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 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 liquefied 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

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 United States or in foreign locations, particularly Canada, the North Sea, East Africa and the Middle East. There are limited processing plants, fractionation facilities and propane production in the northeastern United States.

Propane Demand

Propane demand is typically highest in suburban and rural areas where natural gas is not readily available, such as the northeastern United States. Propane is supplied by wholesalers to retailers to be sold to residential and commercial consumers primarily for heating and industrial applications. Propane demand is typically highest in the winter heating season months of October through April.

Transportation and Storage

Due to the region’s limited propane production and relatively high demand, the northeastern United States is an importer of propane. It relies almost exclusively on pipeline, marine and rail sources for incoming supplies from both domestic and foreign locations. Independent terminal operators and wholesale distributors, own, lease or have access to propane storage facilities 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.” Typically 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.

OUR OPERATING SEGMENTS

Natural Gas Services Segment

LOGO

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, transporting and storing 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 (including the Minden, Ada and Pelico systems), our Southern Oklahoma system (Lindsay system), our 40% equity interest in the Discovery system, our 50.1% operating interest in the East Texas system, our 70% operating interest in the Collbran system, our Douglas system, and our Michigan systems. The Southern Oklahoma and East Texas systems provide operating synergies and opportunities for growth in conjunction with DCP Midstream, LLC. 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 4,700 miles of pipe, four processing plants, six treating plants and two NGL fractionation facilities. The processing plants that service our natural gas gathering systems include one cryogenic facility with approximately 115 MMcf/d of processing capacity, one refrigeration style facility with approximately 45 MMcf/d of processing capacity and two cryogenic facilities, one owned by Discovery and the other by East Texas with our proportionate share at approximately 631 MMcf/ d of processing capacity. Further, our Minden and Discovery processing facilities both have ethane rejection capabilities that serve to optimize the value of the gas stream. The combined NGL production from our processing facilities is in excess of 28,000 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 1,000 MMcf/d, originating from a diversified mix of natural gas producing companies. Our 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.

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:


System	Approximate Gas Gathering and Transmission System (Miles)	Partnership Operated Plants		Plants Operated by Third Party		Partnership Operated Fractionator	Fractionator Operated by Third Party	Approximate Net Plant Capacity (MMcf/d)(a)	2009 Operating Data
System		Partnership Operated Plants		Plants Operated by Third Party		Partnership Operated Fractionator	Fractionator Operated by Third Party	Approximate Net Plant Capacity (MMcf/d)(a)	Natural Gas Throughput (MMcf/d)(a)	NGL Production (Bbls/d)(a)
Minden	725	1	(b)	—		—	—	115	70	4,396
Ada	130	1	(b)	—		—	—	45	44	170
Pelico	600	—		—		—	—	—	162	—
Southern Oklahoma (Lindsay)	225	—		—		—	—	—	19	2,154
Collbran	40	1	(c)	—		—	—	84	61	735
Douglas	1,300	—		—		—	—	—	17	1,835
Michigan	440	5	(c)	—		—	—	495	261	—
Discovery	300	—		1	(b)	—	1	240	182	6,495
East Texas	900	1	(b)	—		1	—	391	256	13,046

Total	4,660	9		1		1	1	1,370	1,072	28,831

(a)	Represents total capacity or total volumes allocated to our proportionate ownership share for 2009 divided by 365 days.

(b)	Represents NGL extraction plants.

(c)	Represents treating plants.

Our Northern Louisiana system includes our Minden, Ada and Pelico systems, which gather natural gas from producers and deliver it for processing to the processing plants. Through our Northern Louisiana system, we offer producers and customers wellhead-to-market services. Our 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, the Minden processing plant was upgraded 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. NGLs produced at the Minden processing plant are delivered to our 45% owned Black Lake pipeline.

The Ada gathering system is located in Bienville and Webster Parish 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. 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.

Our Southern Oklahoma system 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. Natural gas gathered by the system is delivered to a DCP Midstream, LLC processing plant.

Our Collbran system consists of assets in the southern Piceance Basin that gather natural gas at high pressure from over 20,000 dedicated acres in western Colorado. Our original 70% operating interest in the Collbran system was acquired from DCP Midstream, LLC in August 2007 immediately following its acquisition of Momentum Energy Group, Inc, or MEG. We acquired an additional 5% interest in Collbran from Delta Petroleum Corporation in February 2010, bringing our total ownership in the Collbran system to 75%. The remaining 25% interest in the joint venture is held by Occidental Petroleum Corporation who, along with Delta Petroleum Corporation, are the producers on the system. The Collbran system underwent expansion, completed in the third quarter of 2009, which consisted of an additional 24-inch pipeline loop and installation of compression at the Anderson Gulch site. The expansion increased the pipeline capacity to over 200 MMcf/d and enables gas deliveries to the third-party Meeker Plant through a downstream connection with Enterprise Products Partners LP. As a result of our arrangement with Enterprise Products Partners LP, we have decommissioned the processing services at our natural gas processing plant at the Anderson Gulch site. However, this plant will continue to provide treating and compression services.

Our Douglas system consists of over 1,300 miles of natural gas gathering pipelines that cover more than 4,000 square miles in Wyoming. The system gathers primarily rich casing-head gas from oil wells at low pressure and delivers the gas to a third party for processing under a fee agreement. The Douglas system was acquired from DCP Midstream, LLC in August 2007 immediately following its acquisition of MEG.

Our Michigan systems were acquired from Michigan Pipeline & Processing, LLC, or MPP, on October 1, 2008 and from MichCon Pipeline Company in November 2009. These assets consist of five natural gas treating plants and an approximately 330-mile gas gathering pipeline system with throughput capacity of 495 MMcf/d; an approximately 55-mile residue gas pipeline, or Bay Area pipeline; a 75% interest in Jackson Pipeline Company, a partnership owning an approximately 25-mile residue pipeline; and a 44% interest in the 30-mile Litchfield pipeline.

We have a 40% equity interest in Discovery, which we acquired from DCP Midstream, LLC in July 2007. 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 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.”

We have a 50.1% consolidating interest in East Texas. We acquired an initial 25% limited liability company interest in East Texas from DCP Midstream, LLC in July 2007, and an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009. Our East Texas system gathers, transports, treats, compresses and processes natural gas and NGLs. Our East Texas facility may also fractionate NGL production, which can be marketed at nearby petrochemical facilities. Our East Texas system, located near Carthage, Texas, includes 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 and 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 and fractionation capacity of 11,000 Bbls/d.

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. 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 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.

The Southern Oklahoma system has access to a mix of mid-continent pipelines and markets through DCP Midstream, LLC owned processing plants.

The Collbran system in western Colorado gathers, compresses and redelivers unprocessed gas to the third party Meeker plant.

The Douglas system in the Powder River basin in northeastern Wyoming delivers to the Kinder Morgan Interstate Gas Transmission interstate pipeline. The 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 away 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.

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 through its 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.

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 due to the processing value of the gas streams at each of these systems. 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 systems are fee-based agreements. Our gross margin generated from percent-of-proceeds contracts is directly related 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 related to the price of crude oil, with some exceptions, notably in late 2008 to early 2009, when NGL pricing has been at a greater discount to crude oil. 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 relationship. Changes in the relationship of the price of NGLs and crude oil will 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 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 2014.

Discovery’s 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 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

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

LOGO

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, 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 result in our maintaining favorable relationships with our customers and allowing 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.

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 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.

Our Terminals

Our operations include five owned and operated propane rail terminals with aggregate storage capacity of 19 MBbls, 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 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 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.

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 2009 and 2008, our primary suppliers of propane included a subsidiary of DCP Midstream, LLC, Aux Sable Liquid Products LP and Spectra Energy.

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. We entered into a long term contract with Spectra Energy for our marine terminal that offers both product and shipping capabilities.

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 periodically recognize non-cash lower of cost or market inventory adjustments.

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 improved margins and 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 one third-party customer 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 integrated oil and gas and energy companies, and interstate and intrastate pipelines.

NGL Logistics Segment

LOGO

General

We operate our NGL Logistics business in the states of Louisiana and Texas, and from January 2010, we also operate in Colorado and Kansas.

Our 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 95 MBbls/d of capacity, which includes the Wattenberg pipeline acquired in January 2010, and in 2009 average throughput was approximately 30 MBbls/d for Seabreeze, Wilbreeze and Black Lake pipelines.

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 relative natural gas prices reduce the volume of NGLs produced at plants connected to our NGL pipelines.

NGL Pipelines

Seabreeze and Wilbreeze Pipelines. The Seabreeze interstate NGL pipeline is approximately 68-miles long, has capacity of 33 MBbls/d and for 2009 average throughput on the pipeline was approximately 17 MBbls/d. The Seabreeze pipeline, located in Texas, delivers NGLs to a large third-party processing plant with capacity of approximately 340 MMcf/d located in Matagorda County, and a NGL pipeline. 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 southern Texas and offshore in the Gulf of Mexico. The Seabreeze pipeline delivers the NGLs it receives from these sources to a third party fractionator and a third party storage facility. The Wilbreeze interstate pipeline, located in Texas, is approximately 39-miles long, has a current capacity of 11 MBbls/d and average throughput on the pipeline was approximately 6 MBbls/d for 2009.

Wattenberg Pipeline. The Wattenberg NGL pipeline that we purchased in January 2010 is approximately 350 miles long and has capacity of 22 MBbls/d. It originates in the Denver-Julesburg, or DJ, basin in Colorado and terminates near the Conway hub in Bushton, Kansas.

Black Lake Pipeline. The Black Lake interstate NGL pipeline is approximately 317-miles long, has capacity of 40 MBbls/d and for 2009, 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, LLC’s Dubach processing plant and Chesapeake Energy Corporation’s 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 46% of total throughput in 2009. The Black Lake pipeline generates revenues through a FERC-regulated tariff, and the average rate per barrel was $1.07 in 2009, $1.00 in 2008 and $0.95 in 2007.

Black Lake is a partnership that is operated by and 50% owned by BP PLC. We own 45% and DCP Midstream, LLC owns 5%. 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.

Customers and Contracts

The Wilbreeze pipeline is supported by an NGL product dedication agreement with DCP Midstream, LLC.

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. In conjunction with the acquisition of the Wattenberg pipeline in January 2010, we have entered into a 10 year transportation agreement with DCP Midstream, LLC.

Other

For additional information on our segments, please see Item 7. “Management’s 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.”

We have no revenue or segment profit or loss attributable to international activities.

REGULATORY AND ENVIRONMENTAL MATTERS

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

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 up to $8.0 million between 2010 and 2014 to implement integrity management program testing along certain segments of our natural gas transmission and NGL pipelines, including our Wattenberg NGL pipeline acquired in January 2010. 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. We believe that we are in material compliance with the NGPSA and the Pipeline Safety Improvement Act of 2002.

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 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 to be unjust or unreasonable. In addition, FERC 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.

Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. 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 pipeline’s FERC-approved gas tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. FERC-regulated natural gas pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the minimum rate or variable cost of performing service, provided they do not “unduly discriminate.”

Tariff changes can only be implemented upon approval by 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 FERC justifying the proposed tariff change and providing notice, generally 30 days, to the appropriate parties. If FERC determines that a proposed change is just and reasonable as required by the NGA, FERC will accept the proposed change and the pipeline will implement such change in its tariff. However, if FERC determines that a proposed change may not be just and reasonable as required by NGA, then 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 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, FERC may, on 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 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 FERC order requiring this change.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, 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 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, or EPACT 2005, and 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 FERC jurisdiction. In addition, EPACT 2005 gave FERC increased penalty authority for these violations. FERC may now issue civil penalties of up to $1.0 million per day, and there are possible criminal penalties of up to $1.0 million and 5 years in prison. FERC may also order disgorgement of profits obtained in violation of FERC rules. FERC 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 subject to broad interpretation. In the past year, FERC has relied on its EPACT 2005 enforcement authority in issuing a number of natural gas enforcement actions giving rise to the imposition of aggregate penalties exceeding $34.0 million and aggregate disgorgements exceeding $28.0 million. These orders reflect FERC’s view that it has broad latitude in determining whether specific behavior violates the rules. Given FERC’s broad mandate granted in EPACT 2005, if energy prices are high, or exhibit what FERC deems to be “unusual” trading patterns, 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 FERC at least once every three years. The rate review may, but does not necessarily, involve an administrative-type hearing before FERC staff panel and an administrative appellate review. Additionally, the terms and conditions of service set forth in the intrastate pipeline’s 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 pipeline’s 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 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 proposed to require interstate natural gas pipelines and certain non-interstate natural gas pipelines to post capacity, daily 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 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. On January 21, 2010, FERC issued its Order of Rehearing and Clarification, Order No. 720-A, reaffirming most aspects of Order No. 720. The Pelico and East Trans systems are considered major non interstate pipelines and are required to comply with this rule. The deadline for compliance with Order Nos. 720 and 720-A is now July 1, 2010. Compliance with this rule will result in additional administrative burdens related to the associated information technology costs.

On November 20, 2008, FERC issued a Notice of Inquiry, or 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. On July 16, 2009, FERC issued a notice of proposed rulemaking, or NOPR, proposing to revise its contract reporting requirements for pipelines that fall under FERC’s jurisdiction pursuant to Section 311 of the NGPA. FERC proposes that transactional reports be filed on a quarterly basis and include additional types of information. Comments were filed on November 2, 2009. FERC’s NOPR is subject to change based on comments filed and therefore we cannot predict the scope of the final order.

On March 31, 2009, EasTrans, LLC filed a Section 311 rate case with the Railroad Commission of Texas, or TRRC, justifying the current maximum rate applicable to transportation pursuant to Section 311 of the NGPA of $0.1773 per MMBtu. On October 30, 2009, Pelico filed a Section 311 rate case with FERC proposing a maximum rate for transportation pursuant to Section 311 of NGPA of $0.3291 per MMBtu. Both cases are pending approval but are not expected to have a significant impact on earnings.

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 gathering facilities meet the traditional tests FERC has used to establish a pipeline’s 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 where FERC has recognized a jurisdictional exemption for the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated 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. 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 FERC 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 FERC’s 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. 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 FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for pipelines regulated by FERC pursuant to the ICA. 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 pipeline’s increase in costs. If the PPI-FG falls and the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s 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. 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. FERC’s indexing methodology is subject to review every five years; the current methodology is expected to remain in place through June 30, 2011. If 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.

On April 17, 2008, FERC issued a final policy statement regarding the appropriate composition of proxy groups used in discounted flow analysis to determine Return on Equity, or ROE, for oil and gas pipelines subject to cost-of-service rates. FERC concluded, among other things, that MLPs should be included in the

ROE proxy group for both oil and gas pipelines, but required an adjustment of 50 percent for long-term growth projections related to MLP proxies. FERC established a paper hearing for establishing the ROE for cases that were pending before FERC. In January 2010, FERC reaffirmed its new ROE policy statement as it applied those policies in resolving a natural gas pipeline proceeding. The new ROE policies have also been applied by FERC Administrative Law Judge, or ALJs, in oil pipeline proceedings. The policy statement’s ROE policies, as construed and applied by FERC, provide more predictability for ROE determinations and reaffirm the likelihood that ROE results will fall within an acceptable range.

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;

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enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations; and

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regulating changes to the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

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 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. EPA’s December 2009 Endangerment finding relating to greenhouse gasses, or GHGs, and anticipated EPA rules and policies addressing GHGs, may result in additional regulation and control technology requirements for GHGs such as carbon dioxide and methane. 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.

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 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 RCRA’s 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 the application of 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. 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 discharges. 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”, or GHGs, may be contributing to warming of the Earth’s atmosphere, the U.S. Congress continues to consider 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 GHGs, primarily through the planned development of GHG 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., compressor units) or from combustion of fuels (e.g., oil or natural gas) we process. Also, following the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA has declared that GHGs endanger public health and welfare and has taken steps to regulate GHG 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 issued a proposed rule to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, and the rule is expected to be finalized in March 2010. Final action on the greenhouse gas vehicle emission rule will also trigger regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under various Clean Air Act, or CAA, programs at both the federal and state levels, such as the Prevention of Significant Deterioration, or PSD, and Title V. permitting, although recent statement by EPA suggest that these requirements will be delayed for most sources until 2011 or later. New federal or state laws requiring adoption of stringent greenhouse gas control programs 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, 2009, the General Partner or its affiliates employed 9 people directly and approximately 239 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 SEC’s 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.

Item 1A.

Risk Factors

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 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 and quality 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.

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.

We have partial ownership interests in a number of joint venture legal entities, including Discovery 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.

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, the demand for natural gas and crude oil, producers’ desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and our ability to compete for volumes from successful new wells. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of 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, and our ability to make cash distributions.

Current economic conditions may adversely affect natural gas and NGL producers’ drilling activity and transportation spending levels, which may in turn negatively impact our volumes and results of operations and our ability to make distributions to our unitholders.

The level of drilling activity is dependent on economic and business factors beyond our control. Among the factors that impact drilling decisions are natural gas prices, the cost of finding and producing natural gas and the general condition of the credit and financial markets. Natural gas prices are lower in recent periods when compared to historical periods. For example, the twelve-month average New York Mercantile Exchange, or NYMEX, price of natural gas futures contracts per MMBtu was $5.87, $6.21 and $7.96 as of December 31, 2009, 2008 and 2007 respectively. During periods of natural gas price decline the level of drilling activity could decrease. When combined with a reduction of cash flow resulting from recent declines in natural gas prices, a reduction in our producers’ borrowing base under reserve-based credit facilities and lack of availability of debt or equity financing for our producers may result in a significant reduction in our producers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline systems.

Furthermore 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 could lead to reduced utilization of these assets. Other factors that impact production decisions include the ability of producers to obtain necessary 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 declines due to reductions in drilling activity, 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 and our ability to make cash distributions.

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 relates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been 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.

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 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 2014 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 a portion of 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 declines, our commodity price risk will 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 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 portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes from our gathering and processing operations through 2014 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 a portion of 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 one primary suppliers of natural gas represented approximately 16% of the natural gas supplied in our Natural Gas Services segment during the year ended December 31, 2009. In our NGL Logistics segment, our largest NGL supplier is DCP Midstream, LLC, who obtains NGLs from various 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 92% of our propane supplied during the year ended December 31, 2009. 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 at reasonable rates.

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. 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. 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.

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, LP’s 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.

Our assets and operations can be affected by weather and other weather related conditions.

Our assets and operations can be adversely affected by hurricanes, floods, tornadoes, wind, lightening and other natural phenomena, which could impact our results of operations and make it more difficult for us to realize historic rates of return. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss and in some instances, we have been unable to obtain insurance on commercially reasonable terms, if at all. If we incur a significant disruption in our operations or a significant liability for which we were not fully insured, our financial condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.

Weather conditions could also 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 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. FERC’s 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 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.

Discovery’s 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.

FERC, pursuant to the NGA, regulates many aspects of Discovery’s 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 FERC fails to permit tariff rate increases requested by Discovery, or if FERC lowers the tariff rates Discovery is permitted to charge its customers, on its own initiative, or as a result of challenges raised by Discovery’s customers or third parties, Discovery’s tariff rates may be insufficient to recover the full cost of providing interstate transportation service. In certain circumstances, 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 Discovery’s 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, FERC permits pipelines to include, in the cost-of-service used as the basis for calculating the pipeline’s 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 pipeline’s owners have such actual or potential income tax liability will be reviewed by 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 Discovery’s 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 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 in the future associated with proposed climate change legislation.

The United States Congress and some states where we have operations are currently considering legislation related to greenhouse gas emissions. In addition, there have recently been international conventions and efforts to establish standards for the reduction of greenhouse gases globally. The United States Congress is currently considering a number of bills that would compel carbon dioxide emission reductions. Some of these proposals include limitations, or caps, on the amount of greenhouse gas that can be emitted, as well as a system of emissions allowances. The current proposal in the United States Congress places the entire burden of obtaining allowances for the carbon content of natural gas liquids, or NGLs, on the owners of NGLs at the point of fractionation. To the extent legislation is enacted that regulates greenhouse gas emissions, it could significantly increase our costs to (i) acquire allowances; (ii) operate and maintain our facilities; (iii) install new emission controls; and (iv) manage a greenhouse gas emissions program. If such legislation becomes law in the United States or any states in which we have operations and we are unable to pass these costs through as part of our services, it could have an adverse affect on our business and cash available for distributions.

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.

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 up to $8.0 million between 2010 and 2014 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines, including our Wattenberg NGL pipeline acquired in January 2010. 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 plant’s NGL production. We do not, however, currently have commercial arrangements in place with the alternative pipeline. While we 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 could 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, LLC’s basis in the net assets transferred. The amount of the purchase price in excess of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to partners’ equity. The amount of the purchase price in deficit of DCP Midstream’s basis in the net assets, if any, is recognized as an increase to partners’ equity.

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 management’s 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.

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, which may subject us to increased costs.

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, and the operations of third parties 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.

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, including offshore wind. 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.

Volatility in the capital markets may adversely impact our liquidity.

The capital markets may experience volatility, which may lead to 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. If 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 Agreement’s 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 borrowings. A deterioration of 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, matures on June 21, 2012, and consists of an $814.6 million revolving credit facility and a $10.0 million term loan facility for working capital and other general corporate purposes. As of December 31, 2009, the outstanding balance on the revolving credit facility was $603.0 million and the outstanding balance on the term loan facility was $10.0 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.

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 a certain leverage ratio and certain other tests. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. If our covenants are not met, whether as a result of reduced production levels of natural gas and NGLs as described above or otherwise, our financial condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.

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 partner’s 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, LLC’s directors and officers have a fiduciary duty to 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.

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 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 partner’s 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.

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.

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 partner’s 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 currently has the right 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 management’s 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 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 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. As of December 31, 2009, our general partner and its affiliates owned approximately 35% of our aggregate outstanding 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 40% interest in Discovery, a 45% interest in Black Lake 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 SEC 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 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 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.

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. DCP Midstream, LLC holds 11,746,451 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 state’s 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.

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, or IRS, 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 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 counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s 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 unitholder’s 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, or 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.

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.

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-1’s) 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 unitholder’s responsibility to file all United States federal, foreign, state and local tax returns.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

As of March 9, 2010, we owned and operated processing plants and gathering systems located in Arkansas, Colorado, Louisiana, Michigan, Oklahoma, Texas and Wyoming, all within our Natural Gas Services segment, five owned and operated propane rail terminals located in the midwest and northeastern United States, and one propane pipeline terminal located in Pennsylvania within our Wholesale Propane Logistics Segment, two pipelines located in Texas and one pipeline located in Colorado and Kansas within our NGL Logistics segment. In addition, we own 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 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.

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.

Item 3.

Legal Proceedings

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 Driver’s 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 Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, L.P., or El Paso, and against one of our subsidiaries and DCP Midstream, LLC. 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. During the second quarter of 2009 we filed an appeal in the 14th Court of Appeals, Texas. El Paso filed an additional lawsuit in the District Court of Webster Parish, Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the Minden processing plant. The Louisiana court determined in August 2009 that El Paso’s Louisiana claims were barred by the doctrine of res judicata and dismissed the case with prejudice in Louisiana. In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso regarding this matter in Texas and Louisiana. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement, which is within the amount of our previously disclosed contingent liability. This amount was included in the consolidated balance sheets within other current liabilities as of December 31, 2009. The cases have been dismissed in both Texas and Louisiana.

Item 4.

Reserved.

PART II

Item 5.

Market for Registrant’s Common Equity, and Related Unitholder Matters and Issuer Purchases of Units

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. The following table sets forth intra-day high and low sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter for 2009 and 2008.


Quarter Ended	High		Low		Distribution Per Common Unit		Distribution Per Subordinated Unit
December 31, 2009	$	29.70	$	23.99	$	0.600	$	—
September 30, 2009	$	26.20	$	20.33	$	0.600	$	—
June 30, 2009	$	21.80	$	13.58	$	0.600	$	—
March 31, 2009	$	15.06	$	8.59	$	0.600	$	—

December 31, 2008	$	17.45	$	5.26	$	0.600	$	0.600
September 30, 2008	$	31.11	$	16.50	$	0.600	$	0.600
June 30, 2008	$	31.99	$	28.74	$	0.600	$	0.600
March 31, 2008	$	46.00	$	25.51	$	0.590	$	0.590

As of March 9, 2010, there were approximately 44 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.

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.

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP LP Holdings, LP and DCP Midstream GP, LP in consideration for an additional 25.1% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, and the NGL Hedge. The Class D units converted into our common units on a one for one basis on August 17, 2009. The holders of the Class D units received the second quarter distribution paid on August 14, 2009.

Issuance of Registered Units

In November 2009, we issued 2,500,000 common limited partner units at $25.40 per unit, and in December 2009 we issued an additional 375,000 common limited partner units to the underwriters who exercised their overallotment option. We received proceeds of $69.5 million, net of offering costs.

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.

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.

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.

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 our 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 our 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.

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. Please read “Management’s 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 — As of December 31, 2009 the general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1%. 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’s interest may be 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.

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 partner’s incentive distribution rights were not reduced as a result of our recent common limited partner unit offerings, 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 after the Subordination Period sections in Note 13 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 partner’s incentive distribution rights.

On January 26, 2010, the board of directors of DCP Midstream GP, LLC declared a quarterly distribution of $0.60 per unit, which was paid on February 12, 2010, to unitholders of record on February 5, 2010.

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.

Item 6.

Selected Financial Data

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, which have been combined with the historical assets, liabilities and operations of 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 on December 7, 2005, and the historical assets, liabilities and operations of our wholesale propane logistics business which we acquired from DCP Midstream, LLC in November 2006, and our initial 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, and our additional 25.1% limited liability interest in East Texas, which we acquired from DCP Midstream, LLC in April 2009. Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas we owned a 25.0% limited liability company interest in East Texas, which was accounted for under the equity method of accounting. Subsequent to this transaction, we own a 50.1% limited liability company interest in East Texas and account for East Texas as a consolidated subsidiary. These transactions were among entities under common control; accordingly, our financial information includes the historical results of entities and interests contributed to us by DCP Midstream, LLC 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2009(a)			2008(a)			2007(a)			2006			2005
	(Millions, except per unit data)
Statements of Operations Data:
Sales of natural gas, propane, NGLs and condensate	$	913.0		$	1,672.7		$	1,376.5		$	1,232.2		$	1,652.4
Transportation, processing and other		95.2			86.1			57.4			50.0			40.5
(Losses) gains from commodity derivative activity, net(b)		(65.8	)		71.7			(87.7	)		(1.0	)		(2.6	)

Total operating revenues(c)		942.4			1,830.5			1,346.2			1,281.2			1,690.3

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		776.2			1,481.0			1,185.6			1,085.7			1,491.4
Operating and maintenance expense		69.7			77.4			59.3			48.1			42.6
Depreciation and amortization expense		64.9			53.2			40.2			27.4			26.7
General and administrative expense		32.3			33.3			36.2			32.5			24.1
Other		—			(1.5	)		—			—			—

Total operating costs and expenses		943.1			1,643.4			1,321.3			1,193.7			1,584.8

Operating (loss) income		(0.7	)		187.1			24.9			87.5			105.5
Interest income		0.3			6.1			5.6			6.3			0.5
Interest expense		(28.3	)		(32.8	)		(25.7	)		(11.5	)		(0.8	)
Earnings from unconsolidated affiliates(d)		18.5			18.2			24.7			17.2			11.2

Net (loss) income before income taxes		(10.2	)		178.6			29.5			99.5			116.4
Income tax expense		(0.6	)		(0.6	)		(0.8	)		(1.8	)		(3.3	)

Net (loss) income		(10.8	)		178.0			28.7			97.7			113.1
Noncontrolling interest in income		(8.3	)		(36.1	)		(29.8	)		(23.9	)		(28.8	)

Net (loss) income attributable to partners	$	(19.1	)	$	141.9		$	(1.1	)	$	73.8		$	84.3
Less:
Net loss (income) attributable to predecessor operations(e)		1.0			(16.2	)		(18.3	)		(38.5	)		(79.6	)
General partner interest in net income or net loss		(12.7	)		(13.0	)		(3.9	)		(0.6	)		(0.1	)

Net (loss) income allocable to limited partners	$	(30.8	)	$	112.7		$	(23.3	)	$	34.7		$	4.6

Net (loss) income per limited partner unit-basic and diluted	$	(0.99	)	$	4.11		$	(1.14	)	$	1.98		$	0.26


	Year Ended December 31,
	2009(a)		2008(a)		2007(a)		2006		2005
	(Millions, except per unit data)
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	1,000.1	$	882.7	$	737.2	$	423.0	$	405.9
Total assets	$	1,481.5	$	1,419.7	$	1,380.8	$	874.4	$	890.3
Accounts payable	$	128.6	$	107.6	$	223.8	$	164.9	$	198.5
Long-term debt	$	613.0	$	656.5	$	630.0	$	268.0	$	210.1
Partners’ equity	$	377.7	$	395.1	$	232.4	$	318.8	$	369.4
Noncontrolling interests	$	227.7	$	167.7	$	155.1	$	101.7	$	96.9
Total equity	$	605.4	$	562.8	$	387.5	$	420.5	$	466.3

Other Information:
Cash distributions declared per unit	$	2.400	$	2.390	$	2.115	$	1.565	$	0.095
Cash distributions paid per unit	$	2.400	$	2.360	$	1.975	$	1.230		N/A

(a)

Includes the effect of the following acquisitions prospectively from their respective dates of acquisition; (1) Our Southern Oklahoma system acquired in May 2007; (2) certain subsidiaries of Momentum Energy Group, Inc. acquired in August 2007; (3) Michigan Pipeline & Processing, LLC acquired in October 2008; and (4) certain companies acquired from MichCon Pipeline Company in November 2009.

(b)	Includes the effect of the NGL Hedge acquired from DCP Midstream, LLC in April 2009 and the Swap entered into by DCP Midstream, LLC in March 2007 and contributed to us in July 2007.

(c)

We hedge the proportionate ownership of East Texas. Results shown include the unhedged portion of East Texas owned by DCP Midstream, LLC. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

(d)

Includes the effect of the acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC for all periods presented, as well as our proportionate share of the earnings of Black Lake. 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)

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, the net income attributable to the acquisition of an initial 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, and the net income attributable to the acquisition of an additional 25.1% limited liability company interest in East Texas prior to the date of our acquisition from DCP Midstream, LLC in April 2009.

Item 7.

Management’s 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.

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. Our operations are organized into three business segments; Natural Gas Services, Wholesale Propane Logistics and NGL Logistics.

The financial information contained herein includes, for each period presented, our accounts, and the assets, liabilities and operations of (1) our initial 25% limited liability company interest in East Texas, our 40% limited liability company interest in Discovery, and the Swap that we acquired in July 2007, from DCP Midstream, LLC; and (2) our additional 25.1% limited liability company interest in East Texas acquired from DCP Midstream, LLC in April 2009, in transactions among entities under common control, which we refer to collectively as our “predecessor”. 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. Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, we owned a 25% limited liability company interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability interest in East Texas, and account for East Texas as a consolidated subsidiary. Accordingly, our financial information includes the historical results of our predecessors for all periods presented.

The past year presented one of the more difficult business environments in recent history. The global recession resulted in numerous challenges, including turmoil in the capital markets, reduced demand for natural gas and NGLs, lower commodity prices, and a reduction in producer drilling activity. During late 2008 and 2009, the downturn in the economy, excess supplies and reduced industrial demand for natural gas resulted in significantly lower natural gas prices. Furthermore, the lower natural gas prices caused a reduction in producers’ available capital and cash flows and a reduction in the levels of drilling activity and the associated natural gas throughput volumes. The impact of these factors varied across our broad geographic locations. However, drilling levels generally increased over the course of 2009, although they remain lower than their peak in 2008. Since the peak in 2008, we have experienced lower gas throughput volumes at certain of our natural gas assets due to reduced drilling levels. NGLs have been generally related to the price of crude oil, with some exceptions, notably in late 2008 to mid 2009, when NGL pricing was a greater discount to crude oil. However, overall inventory levels for NGLs have declined significantly since early 2009, resulting in improved NGL prices over the same period. During the latter part of 2009, we saw stronger crude oil and NGL prices, although natural gas prices continue to remain lower than recent historical prices. During 2009, demand for propane was negatively impacted by the current recessionary environment.

During the first quarter of 2009, our focus was on restoring to full service our assets that had experienced disrupted operations. Discovery’s offshore gathering system was repaired and placed back into full service following damage sustained from the hurricanes in 2008. We completed the pipeline integrity and system enhancement project on our natural gas gathering system in Wyoming, returning system capacity to full service. In February 2009, a third party owned pipeline ruptured outside the property line of our East Texas facility. The incident caused damages to our natural gas gathering complex and residue natural gas delivery system. Full operating capacity at this facility was restored over the next month.

In 2009, we also executed on the growth elements identified in our business plan. In April we closed on the acquisition of an additional 25.1% interest in East Texas from DCP Midstream, LLC. We also completed our organic expansion projects in East Texas, Discovery and the Piceance basin throughout the course of the year.

There was some improvement in the business environment during the second half of the year as capital markets improved and commodity prices were more favorable. These improvements along with opportunities in the market have enabled us to continue to execute on our growth objective. In November we closed a $45.1 million acquisition of fee-based gathering and treating assets in Michigan that are interconnected with our existing assets. In January 2010, we completed a $22.0 million fee-based acquisition of our Wattenberg NGL pipeline and announced a related $18.0 million expansion capital project.

During this period of financial uncertainty, we have maintained our liquidity and credit metrics. We completed a public equity offering of 2,875,000 common units during the fourth quarter of 2009 that generated net proceeds of $69.5 million. We also received an investment grade rating of BBB-/Stable from Standard & Poor’s, which provides us with benefits in our cost of capital and access to capital markets.

Notwithstanding lower commodity prices and the reduced drilling environment, we achieved solid financial results. Our annual distributable cash flow was the highest since our initial public offering. Additional gas throughput volumes from organic growth projects and acquisitions, along with cost reduction efforts, more than offset volume declines at certain of our natural gas assets. Higher volumes and margins drove strong results in our Wholesale Propane Logistics segment.

General Trends and Outlook

In 2010, our strategic objectives will again focus on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our significant fee-based business representing over 50% of our estimated margins, and our highly hedged commodity position, the objective of which is to protect downside risk in our distributable cash flows.

We expect to incur maintenance capital of approximately $10 to $15 million in 2010 to maintain our existing assets. We also expect to incur expansion capital in 2010 of approximately $30 to $35 million, including approximately $18 million associated with the recently acquired Wattenberg pipeline. This capital does not include any additional investment opportunities that may be identified throughout the course of the year and approved by our management and our Board of Directors.

In 2010 we expect to continue to pursue a multi-faceted growth strategy, including executing on organic opportunities around our footprint, third party acquisitions, and periodic dropdowns from our sponsors in order to grow our distributable cash flows. We also plan to fully integrate our recent acquisitions and execute on the Wattenberg pipeline expansion project, which positions this asset to provide cash flow contributions in early 2011.

We anticipate 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.

Natural Gas Gathering and Processing Margins — Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could decline further should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, natural gas prices should return to a level that would support continued natural gas production in the United States. As we enter 2010, petrochemical demand remains strong for NGLs as NGLs are a lower cost feedstock when compared to crude oil derived feedstocks.

Wholesale Propane Supply and Demand — 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 peak demand periods of tight supply, usually in the winter months when their retail customers consume the most propane for home heating. We expect propane demand to continue to be negatively impacted during 2010 from the current recessionary environment.

Factors That May Significantly Affect Our Results

Natural Gas Services Segment

Our results of operations for our Natural Gas Services segment are impacted by (1) increases and decreases in the volume and quality of natural gas that we gather and transport through our systems, which we refer to as throughput, (2) the associated Btu content of our system throughput and our related processing volumes, (3) the prices of and relationship between commodities such as NGLs, crude oil and natural gas, (4) the operating efficiency of our processing facilities, (5) potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, and (6) the terms of our processing contract arrangements with producers.

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.

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, the commodity pricing environment at the time the contract is executed, customer requirements and competition from other midstream service providers. 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 as well as other market factors.

The capacity on certain downstream NGL and natural gas infrastructure has tightened in recent periods and can be further constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating our facilities optimally.

Our Natural Gas Services segment operating results 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. 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 explore and produce natural gas.

The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close relationship. Due to our hedging program, changes in the relationship of the price of NGLs and crude oil may cause our commodity price exposure to vary, which we have attempted to capture in our commodity price sensitivities in “— Quantitative and Qualitative Disclosures about Market Risk.”

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.

Wholesale Propane Logistics Segment

Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our retail propane distribution customers with reliable supplies of propane. We use physical inventory, physical

purchase agreements and financial derivative instruments, with DCP Midstream, LLC or third parties, which typically match the quantities of propane subject to fixed price sales agreements to mitigate our commodity price risk. Our results may also be impacted as a result of non-cash lower of cost or market inventory adjustments, which occur when the market value of propane declines below our inventory value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory. There may be positive or negative impacts on sales volumes and gross margin from supply disruptions and 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.

The wholesale propane business is highly competitive in our market areas which include the upper midwest and northeastern regions of the United States. Our competitors include major integrated oil and gas and energy companies, and interstate and intrastate pipelines.

NGL Logistics Segment

Our NGL Logistics segment operating results 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. 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.

Weather

The economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in commodity price volatility. 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 availability and propane demand in our Wholesale Propane Logistics segment. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and in certain circumstances we may be unable to obtain insurance on commercially reasonable terms, if at all.

Capital Markets

During the latter part of 2009, the availability of credit through traditional sources of funding such as commercial paper, bank lending and the private and public placement debt markets has largely stabilized from the volatility experienced in 2008 to early 2009. Volatility 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. Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines, to mitigate a portion of these risks.

Impact of Inflation

Inflation has been relatively low in the United States in recent years. However, the inflation rates impacting our business fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of relatively high energy commodity prices.

Other

The above factors, including 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.

Recent Events

On January 26, 2010, the board of directors of the general partner declared a quarterly distribution of $0.60 per unit, payable on February 12, 2010 to unitholders of record on February 5, 2010.

In January 2010, we announced that we acquired an interstate natural gas liquids pipeline from Buckeye Partners, L.P., for $22.0 million in cash, funded with borrowings under our revolving credit facility. The 350-mile pipeline originates in the Denver-Julesburg, or DJ, Basin in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. We expect to spend approximately $18.0 million during 2010 in expansion capital to connect and integrate the acquired pipeline with DCP Midstream, LLC’s facilities, with cash flow contributions commencing in early 2011. In conjunction with the acquisition, we have agreed to a 10-year transportation agreement with DCP Midstream, LLC. The acquired pipeline will generate 100 percent fee-based revenues, with the results of the assets being included in our NGL logistics segment prospectively, from the date of acquisition.

In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso in their lawsuits, filed in Texas and Louisiana, which stemmed from an ongoing commercial dispute involving our Minden processing plant. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement. The original judgment in Texas has now been vacated and all appeals have been dismissed in both Texas and Louisiana. As of December 31, 2009 we held a current liability of approximately $2.2 million in other current liabilities for this matter.

In December 2009, we announced that we received an investment grade credit rating of BBB-/Stable from Standard & Poor’s Ratings Group, or S&P. In addition to our stand-alone credit strengths which include a sizeable portion of fee-based revenues, good geographic diversity and a multi-year commodity hedging program, S&P indicated that the rating reflects the strong linkage that we have with our sponsor DCP Midstream, LLC, which is rated BBB/Stable by S&P. Key analytical considerations included our strategic importance as the growth vehicle for the combined DCP enterprise, a business and assets that are highly integrated with those of DCP Midstream, LLC, and DCP Midstream, LLC’s demonstrated financial support.

In November 2009, we acquired certain natural gas gathering and treating assets for $45.1 million from MichCon Pipeline Company, a subsidiary of DTE Energy. The assets are located in northern Michigan adjacent to the Partnership’s existing assets. These assets provide essential services for gas produced from the Antrim Shale formation. The results of the assets have been included prospectively, from the date of acquisition, as part of the Natural Gas Services segment.

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:

•

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.

•

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 relate directly with the price of natural gas and/or NGLs.

In addition to the above contract types, we have keep-whole arrangements, which are estimated to generate less than 5% of our gross margin. Our equity method investment in Discovery, also has keep-whole arrangements. Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs are sold and the residue natural gas is returned to the producer 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. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.

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 historically 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 one primary supplier of natural gas in our Natural Gas Services segment represented approximately 16% of the natural gas supplied to this system in 2009. 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. In 2009, due to the decline in producer drilling in various areas in which we operate, new well connections have been at reduced levels.

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 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. 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 92% of our propane supplied in 2009. 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 relationships with our customers.

We manage our wholesale propane margins by selling propane to retail propane distributors under annual sales agreements negotiated each spring which specify floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase arrangements. 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 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. DCP Midstream, LLC provides 100% of volumes transported on the Seabreeze and Wilbreeze pipelines. 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, 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) adjusted EBITDA; and (5) distributable cash flow. Gross margin, segment gross margin, adjusted segment gross margin, adjusted EBITDA and distributable cash flow are not measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent permitted we present certain non-GAAP measures and reconciliations of those 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 in which our pipelines are located, 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.

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:

Reconciliation of Non-GAAP Measures


	Year Ended December 31,
	2009			2008			2007
	(Millions)
Reconciliation of net (loss) income to gross margin:
Net (loss) income attributable to partners	$	(19.1	)	$	141.9		$	(1.1	)
Interest expense		28.3			32.8			25.7
Income tax expense		0.6			0.6			0.8
Operating and maintenance expense		69.7			77.4			59.3
Depreciation and amortization expense		64.9			53.2			40.2
General and administrative expense		32.3			33.3			36.2
Other		—			(1.5	)		—
Interest income		(0.3	)		(6.1	)		(5.6	)
Earnings from unconsolidated affiliates		(18.5	)		(18.2	)		(24.7	)
Net income attributable to noncontrolling interests		8.3			36.1			29.8

Gross margin	$	166.2		$	349.5		$	160.6

Reconciliation of segment net (loss) income to segment gross margin:
*Natural Gas Services segment:*
Segment net (loss) income attributable to partners	$	(2.1	)	$	195.7		$	38.7
Operating and maintenance expense		58.2			66.5			48.1
Depreciation and amortization expense		61.9			50.5			37.7
Earnings from unconsolidated affiliates		(16.6	)		(17.4	)		(24.1	)
Noncontrolling interest in income		8.3			36.1			29.8

Segment gross margin	$	109.7		$	331.4		$	130.2

Non-cash commodity derivative mark-to-market(a)	$	(84.2	)	$	99.2		$	(78.3	)

*Wholesale Propane Logistics segment:*
Segment net income attributable to partners	$	37.2		$	1.3		$	14.0
Operating and maintenance expense		10.3			9.9			10.4
Depreciation and amortization expense		1.4			1.3			1.1
Other		—			(1.5	)		—

Segment gross margin	$	48.9		$	11.0		$	25.5

Non-cash commodity derivative mark-to-market(a)	$	0.8		$	2.4		$	(2.8	)

*NGL Logistics segment:*
Segment net income	$	6.9		$	5.5		$	3.3
Operating and maintenance expense		1.2			1.0			0.8
Depreciation and amortization expense		1.4			1.4			1.4
Earnings from unconsolidated affiliates		(1.9	)		(0.8	)		(0.6	)

Segment gross margin	$	7.6		$	7.1		$	4.9

(a)	Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.

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.


	General and Administrative Expense
	Year Ended December 31,
	2009		2008		2007
Affiliate:
Omnibus Agreement	$	9.7	$	9.8	$	7.9
Other — DCP Midstream, LLC		10.4		10.4		12.4
Other — affiliate		0.3		—		—

Total affiliate		20.4		20.2		20.3
Third Party		11.9		13.1		15.9

Total	$	32.3	$	33.3	$	36.2

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 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.

In December 2009 we extended the omnibus agreement through December 31, 2010 for $9.8 million. The Omnibus Agreement also addresses the following matters:

•

DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;

•

DCP Midstream, LLC’s 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 Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness. On December 7, 2009 we received an investment grade credit rating from Standard & Poor’s Ratings Group. DCP Midstream, LLC is no longer obligated to continue to maintain its credit support for our obligations related to derivative financial instruments, in effect as of December 7, 2005, subsequent to this date. As of December 31, 2009, DCP Midstream, LLC has continued to provide parental guarantees totaling $43.0 million in favor of certain counterparties to our commodity derivative instruments; and

•

DCP Midstream, LLC’s 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;

•

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, LLC’s board of directors.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. During the years ended December 31, 2009, 2008 and 2007, East Texas incurred $8.5 million, $8.6 million and $10.3 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

Outside of the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC, which includes expenses for our predecessor operations, of $1.9 million, $1.8 million and $2.1 million, respectively, for the years ended December 31, 2009, 2008 and 2007, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

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.

Adjusted EBITDA and Distributable Cash Flow — We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Adjusted EBITDA is used as a supplemental liquidity and performance measure 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.

Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.

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.

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, net income attributable to noncontrolling interest net of depreciation and income tax, 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 and performance 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.

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, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


										Variance 2009 vs. 2008					Variance 2008 vs. 2007
	Year Ended December 31,									Increase (Decrease)			Percent		Increase (Decrease)			Percent
	2009(a)			2008(a)			2007(a)			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services(b)	$	583.7		$	1,336.2		$	877.0		$	(752.5	)	(56	)%	$	459.2		52	%
Wholesale Propane Logistics		348.2			483.0			459.6			(134.8	)	(28	)%		23.4		5	%
NGL Logistics		10.5			11.3			9.6			(0.8	)	(7	)%		1.7		18	%

Total operating revenues		942.4			1,830.5			1,346.2			(888.1	)	(49	)%		484.3		36	%

Gross margin(c):
Natural Gas Services		109.7			331.4			130.2			(221.7	)	(67	)%		201.2		155	%
Wholesale Propane Logistics		48.9			11.0			25.5			37.9		345	%		(14.5	)	(57	)%
NGL Logistics		7.6			7.1			4.9			0.5		7	%		2.2		45	%

Total gross margin		166.2			349.5			160.6			(183.3	)	(52	)%		188.9		118	%
Operating and maintenance expense		(69.7	)		(77.4	)		(59.3	)		(7.7	)	(10	)%		18.1		31	%
Depreciation and amortization expense		(64.9	)		(53.2	)		(40.2	)		11.7		22	%		13.0		32	%
General and administrative expense		(32.3	)		(33.3	)		(36.2	)		(1.0	)	(3	)%		(2.9	)	(8	)%
Other		—			1.5			—			(1.5	)	(100	)%		1.5		100	%
Earnings from unconsolidated affiliates(d)		18.5			18.2			24.7			0.3		2	%		(6.5	)	(26	)%
Interest income		0.3			6.1			5.6			(5.8	)	(95	)%		0.5		9	%
Interest expense		(28.3	)		(32.8	)		(25.7	)		(4.5	)	(14	)%		7.1		28	%
Income tax expense		(0.6	)		(0.6	)		(0.8	)		—		—	%		(0.2	)	(25	)%
Net income attributable to noncontrolling interests		(8.3	)		(36.1	)		(29.8	)		(27.8	)	(77	)%		6.3		21	%

Net (loss) income attributable to partners	$	(19.1	)	$	141.9		$	(1.1	)	$	(161.0	)	*		$	143.0		*

Operating data:
Natural gas throughput (MMcf/d)(d)		1,072			961			888			111		12	%		73		8	%
NGL gross production (Bbls/d)(d)		28,831			28,000			30,030			831		3	%		(2,030	)	(7	)%
Propane sales volume (Bbls/d)		22,278			21,053			22,798			1,225		6	%		(1,745	)	(8	)%
NGL pipelines throughput (Bbls/d)(d)		30,160			31,407			28,961			(1,247	)	(4	)%		2,446		8	%

*	Percentage change is not meaningful.

(a)	Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company, MPP, MEG and Southern Oklahoma, from their respective acquisition dates of November 2009, October 2008, August 2007 and May 2007.

In April 2009, we completed the acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC, which results in us owning a 50.1% limited liability company interest in East Texas. Prior to this transaction, we accounted for our interest in East Texas under the equity method of accounting. As a result of our owning in excess of 50%, and because the transaction was between entities under common control, we are required to present results of operations, including all historical periods, on a consolidated basis. Therefore, these results as presented are different from those originally reported in 2008 and 2007, which excluded the impact of this transaction.

Our gross margin for our Natural Gas Services segment changed from $206.5 million and $16.2 million as previously reported in 2008 and 2007, to $331.4 million and $130.2 million as currently reported, for the years ended December 31, 2008 and 2007, respectively.

Additionally, while we utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

(b)

Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009, as well as the Swap entered into by DCP Midstream, LLC in March 2007 and contributed to us in July 2007. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component for the period April 2009 to March 2010. The Swap was for a total of 1.9 million barrels at $66.72 per barrel.

(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 NGL production of Collbran, Jackson Pipeline Company, or Jackson, East Texas, Black Lake and Discovery and our proportionate earnings of Black Lake 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.

Year Ended December 31, 2009 vs. Year Ended December 31, 2008

Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:

•

$622.2 million decrease primarily attributable to decreased commodity prices, which impact both sales and purchases, and a decrease in natural gas sales volumes across certain assets. 2009 results include the impact of a fire at East Texas. Results in both years were impacted by hurricanes and operational downtime for our Natural Gas Services segment;

•

$137.5 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $184.8 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $47.3 million due to generally lower average prices of commodities in 2009;

•

$134.9 million decrease primarily attributable to lower propane prices, which impact both sales and purchases, partially offset by increased sales volumes, for our Wholesale Propane Logistics segment; and

•

$2.4 million decrease due primarily to lower NGL throughput volumes partially offset by increased per unit margins, for our NGL Logistics segment.

These decreases were partially offset by:

•

$9.1 million increase in transportation processing and other revenue, which represents our fee-based revenue, primarily attributable to increased throughput volumes due to our Michigan acquisitions, partially offset by decreases in throughput volumes across other assets.

Gross Margin — Gross margin decreased in 2009 compared to 2008, primarily due to the following:

•

$221.7 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity, lower commodity prices and lower natural gas volumes across certain assets. These decreases include the impact of a fire at East Texas in the first quarter of 2009. The decreases were partially offset by increased fee-based throughput volumes due to our Michigan acquisitions. Results in both years were impacted by hurricanes and operational downtime.

These decreases were partially offset by:

•

$37.9 million increase for our Wholesale Propane Logistics segment as a result of increased volumes and margins, a portion of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

•

$0.5 million increase for our NGL Logistics segment, primarily due to higher per-unit margins.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by increased expenses as a result of the Michigan acquisitions.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2009 compared to 2008, primarily as a result of our Michigan acquisitions and our East Texas, Wyoming and Piceance Basin capital projects.

General and Administrative Expense — General and administrative expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by our Michigan acquisitions.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2009 compared to 2008, primarily due to increased earnings from Black Lake, partially offset by decreased earnings from Discovery. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Noncontrolling Interest in Income — Noncontrolling interest in income decreased in 2009 primarily due to lower earnings at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a fire at East Texas.

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:

•

$279.4 million increase primarily attributable to increased commodity prices, which impact both sales and purchases, as well as higher natural gas volumes primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased , NGL and condensate volumes due to the impact of hurricanes, for our Natural Gas Services segment;

•

$159.4 million increase related to 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 gains was an increase in realized cash settlement losses of $24.7 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007;

•

$28.7 million increase in transportation processing and other revenue, which represents our fee-based revenues, primarily attributable to the MEG and MPP acquisitions in our Natural Gas Services segment;

•

$19.0 million increase attributable to higher propane prices, which impact both sales and purchases, 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 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:

•

$201.2 million increase for our Natural Gas Services segment primarily due to increases related to commodity derivative activity, an increase in natural gas production, mainly as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased NGL and condensate 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.

These increases were 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.

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.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2008 compared to 2007, primarily as a result of acquisitions.

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 Unconsolidated Affiliates — Earnings from unconsolidated affiliates 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 $0.2 million from Black Lake.

Interest Expense — Interest expense increased in 2008 compared to 2007, primarily as a result of financing acquisitions, partially offset by lower average interest rates.

Noncontrolling Interest in Income — Noncontrolling interest in income increased in 2008 due to higher earnings at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged.

Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system, a 40% limited liability company interest in Discovery, our Colorado and Wyoming systems, our East Texas systems, and our Michigan systems.


										Variance 2009 vs. 2008					Variance 2008 vs. 2007
	Year Ended December 31,									Increase (Decrease)			Percent		Increase (Decrease)			Percent
	2009(a)			2008(a)			2007(a)			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	562.8		$	1,185.2		$	908.9		$	(622.4	)	(53	)%	$	276.3		30	%
Transportation, processing and other		87.3			79.1			51.7			8.2		10	%		27.4		53	%
(Losses) gains from commodity derivative activity(b)		(66.4	)		71.9			(83.6	)		(138.3	)	*			155.5		*

Total operating revenues		583.7			1,336.2			877.0			(752.5	)	(56	)%		459.2		52	%
Purchases of natural gas and NGLs		474.0			1,004.8			746.8			(530.8	)	(53	)%		258.0		35	%

Segment gross margin(c)		109.7			331.4			130.2			(221.7	)	(67	)%		201.2		155	%
Operating and maintenance expense		(58.2	)		(66.5	)		(48.1	)		(8.3	)	(12	)%		18.4		38	%
Depreciation and amortization expense		(61.9	)		(50.5	)		(37.7	)		11.4		23	%		12.8		34	%
Earnings from unconsolidated affiliates(d)		16.6			17.4			24.1			(0.8	)	(5	)%		(6.7	)	(28	)%

Segment net income		6.2			231.8			68.5			(225.6	)	(97	)%		163.3		238	%
Segment net income attributable to noncontrolling interests		(8.3	)		(36.1	)		(29.8	)		(27.8	)	(77	)%		6.3		21	%

Segment net (loss) income attributable to partners	$	(2.1	)	$	195.7		$	38.7		$	(197.8	)	*		$	157.0		406	%

Operating data:
Natural gas throughput (MMcf/d)(d)		1,072			961			888			111		12	%		73		8	%
NGL gross production (Bbls/d)(d)		28,831			28,000			30,030			831		3	%		(2,030	)	(7	)%

*	Percentage change is not meaningful.

(a)	Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company, MPP, MEG and Southern Oklahoma acquisitions, from their respective acquisition dates of November 2009, October 2008, August 2007 and May 2007.

Additionally, while we utilize commodity derivative instruments to provide stability to distributable cash flows for our ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

(b)

(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 NGL production of Collbran, Jackson, East Texas and Discovery and our proportionate share of the earnings of Discovery for each period presented. Earnings for Discovery 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, 2009 vs. Year Ended December 31, 2008

Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:

•

$560.1 million decrease attributable to decreased commodity prices, which impact both sales and purchases, and includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged;

•

$138.3 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $183.2 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $44.9 million due to generally lower average prices of commodities in 2009; and

•

$62.1 million decrease due primarily to a decrease in natural gas sales volumes across certain assets, partially offset by increased revenues due to contractual amendments such that certain revenues changed from a net presentation to a gross presentation. These results include the impact of a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project.

These decreases were partially offset by:

•

$8.2 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to the Michigan acquisitions, partially offset by decreased throughput volumes across other assets.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased in 2009 compared to 2008, primarily due to decreased commodity prices, which impact both sales and purchases, partially offset by contractual amendments which resulted in a prospective change in certain purchases from a net presentation to a gross presentation.

Segment Gross Margin — Segment gross margin decreased in 2009 compared to 2008, primarily as a result of the following:

•

$138.3 million decrease related to commodity derivative activity, as discussed in the Operating Revenues section above;

•

$78.8 million decrease due to lower commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged; and

•

$21.1 million decrease, primarily due to lower natural gas volumes across certain assets. These decreases include the impact of a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project.

These decreases were partially offset by:

•

$16.7 million increase primarily as a result of increased fee-based throughput volumes due to the Michigan acquisitions.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2009 compared to 2008, primarily as a result of the Michigan acquisitions, and our East Texas, Wyoming and Piceance Basin capital projects.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, decreased in 2009 compared to 2008. This decrease was as a result of a reduction in the recognition of Discovery’s deficit purchase price in 2009 compared to 2008. The reduction of deficit purchase price recognition was partially offset by increased earnings from Discovery. The increase in Discovery’s earnings are primarily as a result of the following variances in earnings drivers, representing 100% of Discovery’s results of operations: Net income increased $2.5 million, or 7%, due primarily to $12.4 million higher gathering and transportation revenue, $13.2 million lower operating and maintenance expense and $2.6 million lower depreciation and accretion expense. These increases were largely offset by $18.5 million lower NGL sales margins resulting from sharply lower average per-unit margins on higher volumes of NGL equity sales and a $5.4 million unfavorable change in other income or expense, net. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Noncontrolling Interest in Income — Noncontrolling interest in income decreased in 2009 compared to 2008 primarily as a result of decreased net income at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a fire at East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2009 compared to 2008, due to increased fee-based throughput volumes from our Michigan acquisitions and increased volumes from the Tahiti project at Discovery, partially offset by decreased volumes across certain assets. Results in both years include the impact of hurricanes and operational downtime following the hurricanes. 2009 results include the impact of a fire at East Texas during the first quarter.

NGL Gross Production — NGL production increased in 2009 compared to 2008, due primarily to increased NGL production from Discovery. Results in both periods include the impact of hurricanes and operational downtime and our Wyoming system pipeline integrity and enhancement project. 2009 results also include the impact of a fire at East Texas during the first quarter.

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:

•

$274.6 million increase attributable to increased commodity prices, which impact both sales and purchases;

•

$155.5 million increase related to commodity derivative activity. This increase in gains 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 gains was an increase in realized cash settlement losses of $23.3 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007;

•

$4.8 million increase attributable to higher natural gas sales volumes, primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased NGL and condensate volumes due to the impact of hurricanes; and

•

$27.4 million increase in transportation, processing and other revenue, which represents our fee-based revenues, 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, which impact both sales and purchases.

Segment Gross Margin — Segment gross margin increased in 2008 compared to 2007, primarily as a result of the following:

•

$152.4 million increase related to commodity derivative activity, as discussed in the Operating Revenues section above;

•

$19.6 million increase due to higher commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged;

•

$18.0 million increase primarily attributable to changes in contract mix; and

•

$11.2 million increase primarily attributable to an increase in natural gas production as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased NGL and condensate volumes due to the impact of hurricanes.

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 Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, decreased in 2008 compared to 2007. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin. Decreased equity earnings were primarily as a result of the following variances in earnings drivers, representing 100% of Discovery’s results of operations: a decrease in Discovery’s 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 FERC rate case settlement.

Noncontrolling Interest in Income — Noncontrolling interest in income increased in 2008, compared to 2007, primarily as a result of higher earnings at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged.

Natural Gas Throughput — 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 Gross Production — NGL production decreased in 2008 compared to 2007, due primarily to decreased NGL production at Discovery and East Texas as a result of the hurricanes.

Results of Operations — Wholesale Propane Logistics Segment

This segment includes our propane transportation facilities, which includes five owned and operated rail terminals, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals.


	Year Ended December 31,									Variance 2009 vs. 2008					Variance 2008 vs. 2007
	2009			2008			2007			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of propane	$	347.2		$	482.1		$	463.1		$	(134.9	)	(28	)%	$	19.0		4	%
Transportation, processing and other		0.4			1.1			0.6			(0.7	)	(64	)%		0.5		83	%
Gains (losses) from commodity derivative activity		0.6			(0.2	)		(4.1	)		0.8		*			(3.9	)	(95	)%

Total operating revenues		348.2			483.0			459.6			(134.8	)	(28	)%		23.4		5	%
Purchases of propane		299.3			472.0			434.1			(172.7	)	(37	)%		37.9		9	%

Segment gross margin(a)		48.9			11.0			25.5			37.9		345	%		(14.5	)	(57	)%
Operating and maintenance expense		(10.3	)		(9.9	)		(10.4	)		0.4		4	%		(0.5	)	(5	)%
Depreciation and amortization expense		(1.4	)		(1.3	)		(1.1	)		0.1		8	%		0.2		18	%
Other		—			1.5			—			(1.5	)	(100	)%		1.5		100	%

Segment net income attributable to partners	$	37.2		$	1.3		$	14.0		$	35.9		2,762	%	$	(12.7	)	(91	)%

Operating Data:
Propane sales volume (Bbls/d)		22,278			21,053			22,798			1,225		6	%		(1,745	)	(8	)%

*	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, 2009 vs. Year Ended December 31, 2008

Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:

•

$163.8 million decrease attributable to lower propane prices, which impact both sales and purchases.

This decrease was partially offset by:

•

$28.9 million increase attributable to increased propane sales volumes; and

•

$0.8 million increase related to commodity derivative activity.

Purchases of Propane — Purchases of propane decreased in 2009 compared to 2008, due to lower propane prices, which impact both sales and purchases, partially offset by increased volumes.

Segment Gross Margin — Segment gross margin increased in 2009 compared to 2008, primarily as a result of increased volumes and per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2009 compared to 2008 due to property taxes, partially offset by our cost reduction initiatives.

Other — Other operating income in 2008 related to payment received from a supplier regarding the early termination of its supply agreement.

Propane Sales Volume — Propane sales volumes increased 6% in 2009 compared to 2008.

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 which impact both sales and purchases; and

•

$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.

These increases were 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 higher propane prices, which impact both sales and purchases, partially offset by decreased 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, lower per unit margins and lower propane sales volumes, partially offset by commodity derivative activity. We estimate that approximately half of the 2008 write downs were recovered through the sale of inventory in 2008.

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.

Propane Sales Volume — Propane sales volume decreased in 2008 compared to 2007, primarily as a result of lower demand.

Results of Operations — NGL Logistics Segment

This segment includes our Seabreeze and Wilbreeze NGL transportation pipelines and our 45% interest in Black Lake.


	Year Ended December 31,									Variance 2009 vs. 2008					Variance 2008 vs. 2007
	2009			2008			2007			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of NGLs	$	3.0		$	5.4		$	4.5		$	(2.4	)	(44	)%	$	0.9		20	%
Transportation, processing and other		7.5			5.9			5.1			1.6		27	%		0.8		16	%

Total operating revenues		10.5			11.3			9.6			(0.8	)	(7	)%		1.7		18	%
Purchases of NGLs		2.9			4.2			4.7			(1.3	)	(31	)%		(0.5	)	(11	)%

Segment gross margin(a)		7.6			7.1			4.9			0.5		7	%		2.2		45	%
Operating and maintenance expense		(1.2	)		(1.0	)		(0.8	)		0.2		20	%		0.2		25	%
Depreciation and amortization expense		(1.4	)		(1.4	)		(1.4	)		—		—	%		—		—	%
Earnings from unconsolidated affiliates(b)		1.9			0.8			0.6			1.1		138	%		0.2		33	%

Segment net income attributable to partners	$	6.9		$	5.5		$	3.3		$	1.4		25	%	$	2.2		67	%

Operating data:
NGL pipelines throughput (Bbls/d)(b)		30,160			31,407			28,961			(1,247	)	(4	)%		2,446		8	%

(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, 2009 vs. Year Ended December 31, 2008

Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to lower throughput volumes, partially offset by higher per unit margins.

Segment Gross Margin — Segment gross margin increased in 2009 compared to 2008, primarily due to higher per unit margins.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2009 compared to 2008, primarily due to decreased operating expenses.

NGL Pipelines Throughput — NGL pipeline throughput decreased in 2009 compared to 2008, due to declines at certain connected processing plants, partially offset by volumes from new interconnects.

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 and settlement of pipeline imbalances, which impacts both sales and purchases.

Segment Gross Margin — Segment gross margin increased in 2008 compared to 2007, primarily due to increased throughput volumes and settlement of pipeline imbalances.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2008 compared to 2007, due to increased throughput at Black Lake.

NGL Pipelines Throughput — 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 and higher commodity prices.

Liquidity and Capital Resources

We expect our sources of liquidity to include:

•

cash generated from operations;

•

cash distributions from our unconsolidated affiliates;

•

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;

•

quarterly distributions to our unitholders;

•

contributions to our unconsolidated affiliates to finance our share of their capital expenditures;

•

business and asset acquisitions; and

•

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.

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.

During the latter part of 2009, there has been a general improvement in the market for and the valuations of equity securities and a general improvement in the availability and cost of funds obtained in the public and private debt markets, as compared with the latter part of 2008 and early 2009. 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 could limit our borrowing capacity, raise our financing costs, as well as impact our compliance with our financial covenant requirements under our Credit Agreement. Our sources of funding could include the placement of public and private debt and the issuance of our common units.

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 portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2014 with fixed price natural gas, crude oil and NGL 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.

We have a 5-year credit agreement, or the Credit Agreement, consisting of an $814.6 million revolving credit facility and a $10.0 million term loan facility as of December 31, 2009. Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts borrowed under the Credit Agreement will not mature prior to the June 21, 2012 maturity date. As of March 9, 2010, we had approximately $212.1 million of borrowing capacity under the Credit Agreement.

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 counterparty’s 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 March 9, 2010, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $103.0 million in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. We pay DCP Midstream, LLC a fee of 0.50% per annum on $60.0 million of these guarantees. As of March 9, 2010, we had a letter of credit of $0.3 million, on which we pay a fee of 0.75% per annum. 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 March 9, 2010, 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, LLC’s credit rating and the thresholds would be reduced to $0 in the event DCP Midstream, LLC’s credit rating were to fall below investment grade.

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 50.1% by us and 49.9% 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. 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, 2009, we had $2.1 million in cash and cash equivalents. Of this balance, as of December 31, 2009, $1.0 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the cash held by these subsidiaries, this cash balance was available for general corporate purposes.

We had working capital of $6.6 million and $52.2 million as of December 31, 2009 and December 31, 2008 respectively. Excluding derivative working capital liabilities of $34.2 million and $2.3 million, working capital would be $40.8 million and $54.5 million as of December 31, 2009 and December 31, 2008, respectively. The change in working capital is primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.

Cash Flow — Operating, investing and financing activities was as follows:


	Year Ended December 31,
	2009			2008			2007
	(Millions)
Net cash provided by operating activities	$	107.9		$	177.6		$	86.5
Net cash used in investing activities	$	(163.8	)	$	(192.2	)	$	(533.6	)
Net cash (used in) provided by financing activities	$	(3.9	)	$	47.2		$	430.2

Our predecessor’s sources of liquidity, prior to its acquisition by us, included cash generated from operations and funding from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s 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 net changes in parent advances to predecessors from DCP Midstream, LLC.

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 received net cash for settlements of our commodity derivative instruments during the year ended December 31, 2009 totaling $16.6 million, approximately $4.8 million of which was associated with rebalancing our portfolio. We paid net cash for settlements of our commodity derivative instruments during the

year ended December 31, 2008 totaling $30.7 million. We paid net cash for settlements of our commodity derivative instruments during the year ended December 31, 2007 totaling $6.0 million.

We and our predecessors received cash distributions from unconsolidated affiliates of $22.4 million, $38.4 million and $23.5 million during the years ended December 31, 2009, 2008 and 2007, respectively. Distributions exceeded earnings by $3.9 million (reflected as $1.7 million in net cash provided by operating activities and $2.2 million in net cash used in investing activities) and $20.2 million for the years ended December 31, 2009 and December 31, 2008, respectively. Earnings exceeded distributions by $1.2 million for the year ended December 31, 2007.

We invested cash in unconsolidated affiliates of $7.0 million, $7.4 million and $3.9 million during the years ended December 31, 2009, 2008 and 2007, respectively, of which $2.8 million, $5.8 million and $3.9 million, respectively, was to fund our share of capital expansion projects, and $4.2 million and $1.6 million in 2009 and 2008, respectively, was to fund repairs to Discovery following damage caused by hurricane Ike in 2008 (of which $2.2 million was returned to us by Discovery during 2009).

Net Cash Used in Investing Activities — Net cash used in investing activities during 2009 was primarily used for: (1) capital expenditures of $164.8 million (our portion of which was $79.7 million and the noncontrolling interest holders’ portion was $85.1 million), which primarily consisted of expenditures for installation of compression and expansion of our East Texas system, expansion of our Collbran system, and the completion of pipeline integrity system upgrades to our Wyoming system; (2) acquisition expenditure of $44.5 million, primarily related to the acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company of $45.1 million; and (3) investments in Discovery of $7.0 million, partially offset by (4) net proceeds from sale of available-for-sale securities of $50.0 million; (5) a return of investment from Discovery of $2.2 million; and (6) proceeds from sale of assets of $0.3 million.

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 $72.7 million (our portion of which was $42.8 million and the noncontrolling interest holders’ portion was $29.9 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 our Wyoming system; and (3) investments in unconsolidated affiliates of $7.4 million, which were partially offset by (4) net proceeds from available-for-sale securities of $42.3 million; and (5) $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 unconsolidated affiliates of $153.3 million; (3) acquisition of the MEG subsidiaries of $142.0 million; (4) capital expenditures of $45.6 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 unconsolidated affiliates of $3.9 million, which were partially offset by (6) net proceeds from available-for-sale securities of $2.4 million; and (7) proceeds from sale of assets of $0.1 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.”

Net Cash (Used in) Provided By Financing Activities — Net cash used in financing activities during 2009 was comprised of: (1) repayments of debt of $280.5 million; (2) distributions to our unitholders and general partner of $85.3 million; and (3) distributions to noncontrolling interests of $27.0 million, partially offset by (4) borrowings of $237.0 million; (5) contributions from non controlling interests of $78.7 million; (6) the issuance of common units for $69.5 million, net of offering costs; (7) net changes in advances to predecessor from DCP Midstream, LLC of $3.0 million; and (7) contributions from DCP Midstream, LLC of $0.7 million.

During 2009, 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 $608.3 million and did not exceed $656.8 million. The weighted average indebtedness outstanding was $656.7 million, $644.4 million, $638.3 million and $620.4 million for the first, second, third and fourth quarters of 2009, respectively.

We had liquidity, which is available commitments under the Credit, of $239.3 million, $221.3 million, $221.3 million and $221.3 million at the end of the first, second, third and fourth quarters of 2009, respectively.

During 2009 we had the following net movements on our Credit Agreement:

•

$50.0 million borrowing under our revolving credit facility to fund a partial repayment of our term loan facility; partially offset by

•

$43.5 million repayment under our revolving credit facility.

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 noncontrolling interests of $21.3 million; (4) contributions from DCP Midstream, LLC of $4.1 million, partially offset by (5) repayment of debt of $633.9 million; (6) distributions to our unitholders and general partner of $76.2 million; (7) distributions to noncontrolling interests of $46.4 million; and (8) net changes in advances from DCP Midstream, LLC relating to our predecessor of $14.2 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 is available commitments under the Credit Agreement, of $364.7 million, $385.4 million, $390.4 million and $228.0 million at the end of the first, second, third and fourth quarters of 2008, respectively.

During 2008, we had the following net movements on our Credit Agreement:

•

$146.4 million borrowing under our revolving credit facility which was used for the Michigan acquisition; partially offset by

•

$79.9 million repayment under our revolving credit facility.

During 2008, we repaid $40.0 million under our term loan facility

Net cash provided by financing activities during 2007 was comprised of: (1) borrowings of $579.0 million; (2) the issuance of common units for $228.5 million, net of offering costs; (3) contributions from noncontrolling interests of $31.6 million; and (4) contributions DCP Midstream, LLC of $0.5 million, partially offset by (5) repayment of debt of $217.0 million; (6) 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; (7) distributions to our unitholders of $44.0 million; (8) distributions to noncontrolling interests of $30.8 million; (8) net change in advances from DCP Midstream, LLC relating to our predecessor of $16.4 million; (9) payment of deferred financing costs of $0.6 million; and (10) purchase of units of $0.3 million.

During 2007, we had the following borrowings:

•

$11.0 million under our revolving credit facility to fund the purchase of the Laser assets from Midstream;

•

$89.0 million under our revolving credit facility to partially fund the Southern Oklahoma acquisition;

•

$88.0 million under a bridge loan to partially fund the Southern Oklahoma acquisition, which was extinguished with borrowings under our revolving credit facility;

•

$246.0 million from our revolving credit facility to finance the acquisition of our interests in East Texas and Discovery;

•

$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

•

$10.0 million from our revolving credit facility for general corporate purposes, which was subsequently repaid.

We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 13 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:

•

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

•

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, 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.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $10.0 million and $15.0 million, and expansion capital expenditures of between $30.0 million and $35.0 million, for the year ending December 31, 2010. The board of directors may approve additional growth capital during the year, at their discretion.

We incur capital expenditures for our consolidated entities. The following table summarizes our maintenance capital and expansion capital expenditures by our portion and our noncontrolling interests’ portion.


	Year Ended December 31, 2009						Year Ended December 31, 2008
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)						(Millions)
Our portion	$	12.6	$	67.1	$	79.7	$	13.6	$	29.2	$	42.8
Noncontrolling interest portion		21.3		63.8		85.1		11.5		18.4		29.9

Total	$	33.9	$	130.9	$	164.8	$	25.1	$	47.6	$	72.7

These amounts do not reflect capital expenditures for our unconsolidated affiliates.

In January 2010, we announced our acquisition of an interstate natural gas liquids pipeline system from Buckeye Partners, L.P. The 350-mile pipeline originates in the DJ Basin in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. We expect to spend approximately $18 million in expansion capital to connect and integrate the acquired pipeline with DCP Midstream, LLC’s facilities, with cash flow contributions commencing in early 2011.

Our expansion project at Collbran was substantially completed and became commercially operational in late September 2009 when Collbran began delivering gas to Enterprise Gas Processing, LLC’s pipeline. We have invested approximately $5.6 million in 2008 and $48.1 million during 2009 on this project.

During the third quarter of 2008, we announced plans, along with DCP Midstream, LLC, to invest approximately $56.0 million in East Texas, our share of which is $14 million, to construct a gathering pipeline to support the East Texas system. In May 2009, service was initiated on the pipeline. As of December 31, 2009, our cumulative net investment in this project is approximately $13.0 million.

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 debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

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 will reduce our discretionary spending.

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 $85.3 million, $76.2 million and $44.0 million during 2009, 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 5-year Credit Agreement consists of an $814.6 million revolving credit facility and a $10.0 million term loan facility, and matures on June 21, 2012. As of December 31, 2009, the outstanding balance on the revolving credit facility was $603.0 million and the outstanding balance on the term loan facility was $10.0 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 or construction 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, 2009 and 2008, we had outstanding letters of credit issued under the Credit Agreement of $0.3 million.

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 Bank’s 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 credit rating. As of December 31, 2009, the weighted-average interest rate on our revolving credit facility was 0.69% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our credit 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 Bank’s prime rate or the Federal Funds rate plus 0.50%. As of December 31, 2009, the interest rate on our term loan facility was 0.34%.

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. Prior to our credit rating that we received on December 7, 2009 from S&P’s Ratings Group, the Credit Agreement required 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. As a result of our credit rating, we are no longer required to maintain this interest coverage ratio.

S&P considers “BBB-” the lowest investment grade rating, and a rating below investment grade indicates that the security has significant speculative characteristics. With respect to S&P, a rating of “BBB” or above indicates an investment grade rating. S&P may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating organization.

Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of December 31, 2009, is as follows:


	Payments Due by Period
	Total		2010		2011-2012		2013-2014		2015 and Thereafter
	(Millions)
Long-term debt(a)	$	677.1	$	26.7	$	650.4	$	—	$	—
Operating lease obligations(b)		51.0		14.0		23.5		11.8		1.7
Purchase obligations(c)		946.7		261.1		359.8		234.2		91.6
Other long-term liabilities(d)		9.1		—		0.3		0.2		8.6

Total	$	1,683.9	$	301.8	$	1,034.0	$	246.2	$	101.9

(a)

Includes interest payments on long-term debt that has been hedged. Interest payments on long-term debt that has not been hedged are not included as these payments are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments.

(b)

Our operating lease obligations are off-balance sheet obligations, and primarily consist of our leased marine propane terminal and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics business. Operating lease obligations also include firm transportation arrangements and natural gas storage for our Pelico system. The firm transportation arrangements supply off-system natural gas to Pelico and the natural gas storage arrangement enables us to maximize the value between the current price of natural gas and the futures market price of natural gas.

(c)

Our purchase obligations are off balance sheet obligations and include $6.0 million of purchase orders for capital expenditures and $940.7 million of various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business. For contracts where the price paid is based on an index, the amount is based on the forward market prices at December 31, 2009. 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.

(d)	Other long-term liabilities include $8.5 million of asset retirement obligations and $0.6 million of environmental reserves recognized in the consolidated balance sheet at December 31, 2009.

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.”


Description	Judgments and Uncertainties	Effect if Actual Results Differ from 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, 2009 weighted-average cost, our net income would be affected by approximately $3.4 million.

Impairment of Goodwill
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. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. 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 goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. We have not recorded any impairment charges on goodwill during the year ended December 31, 2009. The carrying value of goodwill as of December 31, 2009 by reporting unit was $52.8 million for our Collbran system, $29.3 million for our Wholesale Propane Logistics business and $10.0 million for our Michigan systems, totaling $92.1 million.


Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
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 asset’s 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 any impairment charges on long-lived assets during the year ended December 31, 2009. 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, 2009 was $1,060.6 million.

Impairment of Investments in Unconsolidated Affiliates
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate, in management’s 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 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.	Using the impairment review methodology described herein, we have not recorded any impairment charges on investments in unconsolidated affiliates during the year ended December 31, 2009. If the estimated fair value of our unconsolidated affiliates 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 unconsolidated affiliates as of December 31, 2009 was $114.6 million.


Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
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 contract’s 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 the expected relationship 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, 2009 would have affected net income by approximately $5.8 million for the year ended December 31, 2009.

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.

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, 2009, would not have had a significant effect on net income.

Recent Accounting Pronouncements

On July 1, 2009, the Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, became the source for authoritative U.S. Generally Accepted Accounting Principles, or GAAP, as noted in the discussion of Accounting Standards Update, or ASU, 2009-01 below. During the current quarter, the FASB issued several ASUs and ASCs. The following outlines the ASUs and ASCs that are applicable to us and may have an impact on our consolidated financial statements and related disclosures:

ASU 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended ASC topic 820-10 “Fair Value Measurement and Disclosures — Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 are effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we will disclose information in accordance with the revised provisions of ASU 2010-06 within all financial statements issued after the effective date of the ASU.

ASU 2010-02 “Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary — a Scope Clarification,” or ASU 2010-02 — In January 2010, the FASB issued ASU 2010-02 which amended ASC topic 810-10 “Consolidation — Overall.” ASU 2010-02 clarifies guidance on the scope of the decrease in ownership provisions of ASC 810-10 and expands the disclosures about the deconsolidation of a subsidiary and the derecognition of a group of assets. ASU 2010-02 was effective for us on January 1, 2009. We have not had any transactions that would fall under the scope of the revised guidance of ASU 2010-02 and consequently there was no impact on our consolidated results of operations, cash flows and financial position as a result of adoption.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This SFAS became effective on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our consolidated results of operations, cash flows and financial position as a result of adoption.

ASU 2009-05 “Fair Value Measurements and Disclosures (Topic 820) Measuring Liabilities at Fair Value,” or ASU 2009-05 — In August 2009, the FASB issued ASU 2009-05 which amended ASC Topic 820-10 “Fair Value Measurements and Disclosures — Overall” for the fair value measurement of liabilities. The amended provisions in this update are designed to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities, helping to improve the consistency in the application of Topic 820 “Fair Value Measurements and Disclosures.” ASU 2009-05 became effective on October 1, 2009 and there was no impact on our consolidated results of operations, cash flows or financial position as a result of adoption.

ASU 2009-01 “Topic 105 — Generally Accepted Accounting Principles,” or ASU 2009-01 — In June 2009, the FASB issued ASU 2009-01, which amended ASC Topic 105 “Generally Accepted Accounting Principles,” or ASC 105 which establishes the FASB ASC as the source of authoritative GAAP. The ASC supersedes all existing non-SEC accounting and reporting standards. We adopted the amended provisions of ASC 105 effective September 15, 2009, and have included all required disclosures in this filing. The amended provisions of ASC 105 impacts only disclosures so there was no effect on our consolidated results of operations, cash flows or financial position as a result of adoption.

ASC 260 “Earnings per Share,” or ASC 260 — In March 2008, the FASB amended guidance relating to earnings per share. The amendment seeks to improve the comparability of earnings per unit, or EPU, calculations for master limited partnerships with incentive distribution rights. We adopted these amended provisions effective January 1, 2009. As a result of adopting the amended provisions, undistributed earnings or losses are reduced or increased, respectively, by the amount of available cash that was generated during the current period, and undistributed earnings are no longer allocated to our general partner with respect to its incentive distribution rights, as our partnership agreement specifically limits incentive distributions to available cash. These amended provisions are applied retrospectively for all periods. We have retrospectively restated our previously disclosed net income (loss) per limited partner unit, or LPU, and related disclosures, within this filing. As a result of adoption, net income per LPU increased from $3.25 per unit to $4.11 per unit and net loss increased from $(1.05) per unit to $(1.14) per unit for the years ended December 31, 2008 and 2007, respectively.

ASC 320 “Investments — Debt and Equity Securities,” or ASC 320 — In April 2009, the FASB amended the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. We adopted these amended provisions effective June 30, 2009 and there was no impact on our consolidated results of operations, cash flows or financial position.

ASC 323 “Investments — Equity Method and Joint Ventures,” or ASC 323 — In November 2008, the FASB amended guidance on equity method investments. This issue addresses a) how the initial carrying value of an equity method investment should be determined; b) how impairment assessment of an underlying indefinite-lived intangible asset of an equity method investment should be performed; c) how an equity method investee’s 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 amendment became effective for us on January 1, 2009, and although it has not impacted the manner in which we apply equity method accounting for our current equity method investments, we will apply this guidance to future transactions with equity method investees.

ASC 350 “Intangibles — Goodwill and Other,” or ASC 350, ASC 275 “Risks and Uncertainties,” or ASC 275 — In April 2008, the FASB amended guidance relating to intangible assets and risks and uncertainties, for factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset. We adopted these amended provisions on January 1, 2009. As a result of acquisitions, we have intangible assets for customer contracts and related relationships in our consolidated balance sheets. Generally, costs to renew or extend such contracts are not significant, and are expensed to the consolidated statements of operations as incurred. During the year ended December 31, 2009, there were no contracts that were recognized as intangible assets that were renewed or extended.

ASC 805 “Business Combinations,” or ASC 805 — In April 2009, the FASB amended guidance relating to business combinations, providing additional guidance on the valuation of assets and liabilities assumed in a business combination that arise from contingencies, which would otherwise be subject to the provisions of other applicable GAAP. This amendment emphasizes that assets and liabilities assumed in a business combination that have an estimated fair value should be recorded at the time of acquisition. Assets and liabilities where the fair value may not be determinable during the measurement period will continue to be recognized pursuant to other applicable GAAP. This amendment was effective for us for business combinations with closing dates subsequent to January 1, 2009. We have accounted for business combinations with closing dates subsequent to the effective date in accordance with this new guidance.

In December 2007, the FASB amended guidance relating to business combinations, which requires the acquiring entity in a business combination subsequent to January 1, 2009 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. We adopted these amended provisions effective January 1, 2009, and have accounted for all transactions with closing dates subsequent to adoption in accordance with the revised provisions of this standard.

ASC 810 “Consolidation,” or ASC 810 — In December 2007, the FASB amended guidance relating to consolidation, 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 parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. These amended provisions also establish reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We adopted these amended provisions effective January 1, 2009, which required retrospective restatement of our consolidated financial statements for all periods presented in this filing.

ASC 815 “Derivatives and Hedging,” or ASC 815 — In March 2008, the FASB amended guidance relating to derivatives and hedging to require 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 entity’s financial position, financial performance and cash flows. We adopted these amended provisions effective January 1, 2009, and have included all required disclosures in this filing. The amended provisions impact only disclosures, so there was no effect on our consolidated results of operations, cash flows or financial position as a result of adoption.

ASC 820 “Fair Value Measurements and Disclosures,” or ASC 820 — In April 2009, the FASB amended guidance relating to fair value measurements and disclosures, which provides additional guidance on the valuation of assets or liabilities that are held in markets that have seen a significant decline in activity. While this amendment does not change the overall objective of determining fair value, it emphasizes that in markets with significantly decreased activity and the appearance of non-orderly transactions, an entity may employ multiple valuation techniques, to which significant adjustments may be required, to determine the most appropriate fair value. During 2009, certain of the markets in which we transact have seen a decrease in overall volume; however, we believe that these markets continue to provide sufficient liquidity such that transactions are executed in an orderly manner at fair value. We adopted these amended provisions effective June 30, 2009 and there was no impact on our consolidated results of operations, cash flows or financial position.

On January 1, 2008 we adopted the fair value measurement and disclosure requirements of ASC 820 for all financial assets and liabilities. Effective January 1, 2009, we adopted the fair value measurement and disclosure requirements for all nonfinancial assets and liabilities. There was no effect on our consolidated results of operations, cash flows, or financial position, and we have included all required disclosures as a result of the adoption of these requirements relative to nonfinancial assets and liabilities.

ASC 825 “Financial Instruments,” or ASC 825 — In April 2009, the FASB amended guidance relating to financial instruments, requiring disclosure of summarized financial information for financial instruments. We have instruments that are subject to the fair value disclosure requirements of ASC 825, and are subject to the amended provisions of this guidance. We adopted these amended provisions effective June 30, 2009 and there was no impact on our consolidated results of operations, cash flows or financial position.

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 a portion of the effects of identified risks. In general, we attempt to mitigate a portion of the 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, LLC’s 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, LLC’s corporate credit policy. DCP Midstream, LLC’s 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, LLC’s 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 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, 2009, the effective weighted-average interest rate on our $603.0 million of outstanding revolver debt was 4.41%, 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 $38.0 million as of December 31, 2009, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $0.2 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, sales and storage 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, crude oil and NGL contracts to mitigate a portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of these instruments prior to their maturity.

We enter into derivative financial instruments to mitigate a portion of the cash flow risk of decreased natural gas, NGL and condensate prices associated with our percent-of-proceeds arrangements and gathering operations. We also may enter into natural gas derivatives to lock in margin around our transportation or leased storage assets. Historically, there has been a strong relationship between NGL prices and crude oil prices, with some exceptions, notably in late 2008 and early 2009, and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is outside of historical ranges, we experience additional exposure as a result of the relationship. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2014.

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.

The following table sets forth additional information about our fixed price natural gas and crude oil swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations, as of March 9, 2010:


Period	Commodity	Notional Volume	Reference Price	Swap Price Range
January 2010 — December 2010	Natural Gas	1,634 MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$3.94/MMBtu
January 2011 — December 2012	Natural Gas	1000/ MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$5.89/MMBtu

January 2010 — December 2010	Natural Gas	1,900 MMBtu/d	Texas Gas Transmission Price (b)	$6.41 - $9.20/MMBtu
January 2011 — December 2012	Natural Gas	1,100 MMBtu/d	Texas Gas Transmission Price (b)	$6.41 - $6.80/MMBtu
January 2010 — December 2013	Natural Gas	1,000 MMBtu/d	NYMEX Final Settlement Price (c)	$8.22/MMBtu
January 2010 — December 2013	Natural Gas Basis	1,000 MMBtu/d	IFERC Monthly Index Price for Panhandle Eastern Pipe Line (d)	NYMEX less $0.68/MMBtu
January 2010 — December 2010	Crude Oil	2,415 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$63.05 - $87.25/Bbl
April 2010 — December 2011	Crude Oil	250 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$56.75 - $59.30/Bbl
January 2011 — December 2011	Crude Oil	2,350 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$66.72 - $83.80/Bbl
January 2012 — December 2012	Crude Oil	2,125 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$66.72 - $90.00/Bbl
January 2013 — December 2013	Crude Oil	2,050 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$67.60 - $83.00/Bbl
January 2014 — December 2014	Crude Oil	1,000 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$74.90 - $84.70/Bbl
January 2010 — March 2010	NGLs	839 Bbls/d	Mt. Belvieu Non-TET (f)	$0.66 - $1.63/Gal

(a)	The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline.

(b)	The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area.

(c)	NYMEX final settlement price for natural gas futures contracts (NG).

(d)	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.

(e)	Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).

(f)	The average monthly OPIS price for Mt. Belvieu Non-TET.

At December 31, 2009 the aggregate fair value of the fixed price natural gas, crude oil and NGL swaps described above was a net gain of $1.9 million, a net loss of $60.2 million and $0.6 million, respectively.

Given our current contract mix and the commodity derivative contracts we have in place, we have updated our annualized sensitivities for 2010 as shown in the table below, which excludes the impact from mark-to-market on our commodity derivatives. We utilize crude oil and NGL derivatives to mitigate a portion of our commodity price exposure for NGLs. We have combined the NGL and crude oil sensitivities into one factor, and also show 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.

Commodity Sensitivities Excluding Non-Cash Mark-To-Market


	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	0.2
Crude oil prices(a)	$	5.00	Barrel	$	1.3
NGL to crude oil price relationship(b)		5 percentage point change	Barrel	$	5.6

(a)	Assuming 60% NGL to crude oil price relationship.

(b)

Assuming 60% NGL to crude oil price relationship and $70.00/Bbl crude oil price. Generally, this sensitivity changes by $1.6 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from $70.00/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 $70.00/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 2010 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


	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market Impact (Decrease in Net Income Attributable to Partners)
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	4.0
Crude oil prices	$	5.00	Barrel	$	18.4
NGL prices	$	0.10	Gallon	$	0.3

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 relationship 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 related to the price of crude oil, with some exceptions, notably in late 2008 and early 2009, when NGL pricing was 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. 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 portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2014. Given the historical relationship between NGL prices and crude prices and the lack of liquidity in the NGL financial market, we have generally used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is outside of historical ranges, we experience additional exposure as a result of the relationship.

Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices 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, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. We believe that future natural gas prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and imports of liquid natural gas, or LNG, from foreign locations. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also further reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall below demand levels.

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 contract’s 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 contract’s 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 relationship 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, 2009
Sources of Fair Value	Total			Maturity in 2010			Maturity in 2011-2012			Maturity in 2013-2014			Maturity in 2015 and Thereafter
	(Millions)
Prices supported by quoted market prices and other external sources	$	(89.6	)	$	(33.8	)	$	(40.7	)	$	(15.1	)	$	—
Prices based on models or other valuation techniques		(0.6	)