SEC Filing | DCP Midstream, LP

View:

Download DOC

Download PDF

Download XLS

Form 8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): October 10, 2007

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware

001-32678

03-0567133

(State or other jurisdiction

of incorporation)

(Commission File Number)

(IRS Employer

Identification No.)

370 17^th Street, Suite 2775

Denver, Colorado

80202

(Address of principal executive offices)

(Zip Code)

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

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

This Amendment No. 2 to the Current Reports on Form 8-K is filed as an amendment (“Amendment No. 2”) to the Current Reports on Form 8-K (File No. 001-32678) filed by DCP Midstream Partners, LP (“DCP”) under Items 1.01, 2.01, 2.03, 3.02, 7.01 and 9.01 on July 2, 2007, September 5, 2007 and October 3, 2007 (the “Initial 8-K’s”). The information included in Items 1.01, 2.01, 2.03, 3.02, 7.01 and 9.01 of the Initial 8-K’s is incorporated herein by reference. Amendment No. 2 is being filed to restate the financial statements included in the July 2, 2007 Form 8-K and the October 3, 2007 Form 8-K, to reflect the capitalization of certain pipeline assets of the East Texas Midstream Business that were improperly expensed. This Current Report on Form 8-K does not modify the financial statements of Discovery Producer Services LLC or Momentum Energy Group, Inc. and Subsidiaries set forth in the Initial 8-K’s.

This current report on Form 8-K does not otherwise update the disclosures set forth in the Initial 8-K’s and does not otherwise reflect events occurring after the original filing of such documents.

Item 4.02

Non-Reliance on Previously Issued Financial Statements or a Related Audit Report or Completed Interim Review

On July 1, 2007, DCP acquired from the owner of its general partner, DCP Midstream, LLC, and two of its wholly-owned subsidiaries, DCP LP Holdings, LP and DCP Midstream GP, LP the following interests: (i) a 40% limited liability company interest in Discovery Producer Services LLC, and (ii) a 25% limited liability company interest in the East Texas Midstream Business. On October 10, 2007, it was determined that expenditures related to a capital project that commenced in 2006 at the East Texas Midstream Business had been improperly expensed to operating and maintenance expense, and should have instead been capitalized in property, plant and equipment, net as they increase the capacity of a gathering and pipeline asset owned by the East Texas Midstream Business. As a result, it was determined that operating and maintenance expense was overstated and property, plant and equipment, net was understated in the East Texas Midstream Business financial statements as of and for the year ended December 31, 2006, as of and for the three months ended March 31, 2007, and as of and for the six months ended June 30, 2007. Operating expenses were overstated by approximately $0.8 million, $1.2 million and $2.3 million for the year ended December 31, 2006, for the three months ended March 31, 2007, and for the six months ended June 30, 2007. Property, plant and equipment, net were understated by approximately $0.8 million, $2.0 million and $3.1 million as of December 31, 2006, March 31, 2007 and June 30, 2007. An authorized officer of the general partner of the general partner of DCP discussed this matter with DCP’s independent registered public accounting firm.

Due to this error in accounting, on October 10, 2007, DCP determined that the combined financial statements of the East Texas Midstream Business as of and for the year ended December 31, 2006, as of and for the three months ended March 31, 2007, and as of and for the six months ended June 30, 2007, should no longer be relied upon.

Filed herewith to this Form 8-K are (i) restated combined financial statements of the East Texas Midstream Business as of and for the year ended December 31, 2006, as of and for the three months ended March 31, 2007, and as of and for the six months ended June 30, 2007, and (ii) the restated unaudited condensed consolidated pro forma financial statements of DCP for the year ended December 31, 2006, as of and for the three months ended March 31, 2007, and as of and for the six months ended June 30, 2007.

Item 9.01

Financial Statements and Exhibits.

(a)

Financial statements of businesses acquired.

Audited combined financial statements of the East Texas Midstream Business as of December 31, 2006 (restated) and 2005, and for the years ended December 31, 2006 (restated), 2005 and 2004, and unaudited combined financial statements of the East Texas Midstream Business as of June 30, 2007 (restated) and March 31, 2007 (restated), for the six months ended June 30, 2007 (restated) and 2006, and for the three months ended March 31, 2007 (restated) and 2006, are attached hereto as Exhibit 99.2, and are incorporated herein by reference.

(b)

Pro forma financial information.

The unaudited pro forma condensed consolidated financial statements of DCP as of June 30, 2007 (restated) and March 31, 2007 (restated), and for the six months ended June 30, 2007 (restated), for the three months ended March 31, 2007 (restated), and for the year ended December 31, 2006 (restated), are attached hereto as Exhibit 99.4, and are incorporated herein by reference. Unaudited pro forma condensed consolidated financial statements of DCP for the years ended December 31, 2005 and 2004 were attached as Exhibit 99.5 to Form 8-K (File No. 001-32678) filed by DCP on July 2, 2007.

(c)

Not applicable.

(d)

Exhibits.


Exhibit Number		Description
Exhibit 23.2		Consent of Deloitte & Touche LLP on East Texas Midstream Business’ Combined Financial Statements as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004.

Exhibit 99.2		Restated audited and unaudited historical combined financial statements of the East Texas Midstream Business.

Exhibit 99.4		Restated unaudited pro forma condensed consolidated financial statements of DCP Midstream Partners, LP.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	DCP Midstream Partners, LP

	By:	DCP Midstream GP, LP
		its General Partner

	By:	DCP Midstream GP, LLC
		its General Partner

Date: October 16, 2007	/s/ Thomas E. Long
	Name:	Thomas E. Long
	Title:	Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description
Exhibit 23.2		Consent of Deloitte & Touche LLP on East Texas Midstream Business’ Combined Financial Statements as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004.

Exhibit 99.2		Restated audited and unaudited historical combined financial statements of the East Texas Midstream Business.

Exhibit 99.4		Restated unaudited pro forma condensed consolidated financial statements of DCP Midstream Partners, LP.

Consent of Deloitte & Touche LLP

Exhibit 23.2

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8 of DCP Midstream Partners, LP of our report dated June 29, 2007 (October 16, 2007, as to the effects of the restatement discussed in Note 10) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the combined financial statements of the East Texas Midstream Business from the separate records maintained by DCP Midstream, LLC) relating to the combined financial statements of the East Texas Midstream Business as of December 31, 2006 and 2005 and for the three years in the period ended December 31, 2006 appearing in Amendment No. 2 to this Current Report on Form 8-K dated October 10, 2007.

/s/ Deloitte & Touche LLP

Denver, Colorado

October 16, 2007

Restated audited and unaudited historical combined financial statements

Exhibit 99.2

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED FINANCIAL STATEMENTS

AS OF JUNE 30, 2007 (RESTATED) (UNAUDITED) AND MARCH 31, 2007 (RESTATED) (UNAUDITED),

AND DECEMBER 31, 2006 (RESTATED) AND 2005,

AND FOR THE PERIODS ENDED JUNE 30, 2007 (RESTATED) (UNAUDITED)

AND 2006 (UNAUDITED), MARCH 31, 2007 (RESTATED) (UNAUDITED) AND 2006 (UNAUDITED),

AND DECEMBER 31, 2006 (RESTATED), 2005 AND 2004

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of

DCP Midstream, LLC

Denver, Colorado

We have audited the accompanying combined balance sheets of the East Texas Midstream Business (the “Business”), which consist of assets which are under common ownership and common management, as of December 31, 2006 and 2005, and the related combined statements of operations, changes in net parent equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Business’ management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the combined financial position of the Business at December 31, 2006 and 2005, and the combined results of its operations and its combined cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

The accompanying combined financial statements have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Business had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, DCP Midstream, LLC as a whole.

/s/ Deloitte & Touche LLP

Denver, Colorado

June 29, 2007 (October 16, 2007 as to the effects of the restatement discussed in Note 10)

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED BALANCE SHEETS

($ in millions)


	June 30, 2007		March 31, 2007		December 31,
	June 30, 2007		March 31, 2007		2006		2005
	(As Restated — Note 10)		(As Restated — Note 10)		(As Restated — Note 10)
	(unaudited)
ASSETS
Current assets:
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.3 million (unaudited), $0.2 million (unaudited), $0.2 million and $0.1 million, respectively	$	25.4	$	14.9	$	30.1	$	22.5
Affiliates		1.1		0.2		0.1		2.5
Other		0.2		0.7		0.8		6.2
Other		0.1		0.1		0.1		0.1

Total current assets		26.8		15.9		31.1		31.3
Property, plant and equipment, net		235.6		232.0		228.3		227.2
Other non-current assets		—		—		—		0.1

Total assets	$	262.4	$	247.9	$	259.4	$	258.6


LIABILITIES AND NET PARENT EQUITY
Current liabilities:
Accounts payable:
Trade	$	46.8	$	33.6	$	44.4	$	51.9
Affiliates		0.1		0.2		0.6		5.4
Other		2.2		2.3		2.6		2.9
Other		5.6		4.8		5.8		3.7

Total current liabilities		54.7		40.9		53.4		63.9
Deferred income taxes		1.8		1.8		1.8		—
Other long-term liabilities		0.5		0.5		0.5		0.7

Total liabilities		57.0		43.2		55.7		64.6

Commitments and contingent liabilities

Net parent equity		205.4		204.7		203.7		194.0

Total liabilities and net parent equity	$	262.4	$	247.9	$	259.4	$	258.6

See accompanying notes to combined financial statements.

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF OPERATIONS

($ in millions)


	Six Months Ended June 30,				Three Months Ended March 31,				Year Ended December 31,
	2007		2006		2007		2006		2006			2005			2004
	(unaudited)				(unaudited)
	(As Restated —Note 10)				(As Restated —Note 10)				(As Restated —Note 10)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	28.2	$	113.9	$	13.9	$	57.8	$	177.7		$	164.7		$	64.7
Sales of natural gas, NGLs and condensate to affiliates		166.2		144.9		75.5		78.4		286.6			365.6			308.1
Transportation and processing services		9.9		9.2		4.8		4.6		21.9			17.1			13.4
Transportation and processing services to affiliates		0.1		0.2		0.1		0.1		0.3			0.3			0.3
Gains (losses) from non-trading derivative activity — affiliates		0.1		0.3		0.1		0.1		(1.1	)		(1.7	)		(0.1	)

Total operating revenues		204.5		268.5		94.4		141.0		485.4			546.0			386.4

Operating costs and expenses:
Purchases of natural gas and NGLs		155.9		209.7		71.6		111.9		376.0			418.8			306.7
Purchases of natural gas and NGLs from affiliates		1.1		5.3		0.6		4.4		9.3			25.3			3.6
Operating and maintenance expense		13.4		11.1		6.2		5.8		24.4			20.2			16.3
Depreciation expense		7.9		7.1		3.7		3.5		14.6			14.0			14.4
General and administrative expense		1.2		0.2		—		—		0.2			0.1			0.3
General and administrative expense — affiliate		6.0		4.9		2.8		2.4		11.3			9.8			8.1

Total operating costs and expenses		185.5		238.3		84.9		128.0		435.8			488.2			349.4

Operating income		19.0		30.2		9.5		13.0		49.6			57.8			37.0
Income tax expense		0.2		1.8		—		—		1.8			—			—

Net income	$	18.8	$	28.4	$	9.5	$	13.0	$	47.8		$	57.8		$	37.0

See accompanying notes to combined financial statements.

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CHANGES IN NET PARENT EQUITY

($ in millions)


Balance, January 1, 2004	$	236.5
Net change in parent advances		(53.5	)
Net income		37.0

Balance, December 31, 2004		220.0
Net change in parent advances		(83.8	)
Net income		57.8

Balance, December 31, 2005		194.0
Net change in parent advances		(38.1	)
Net income (As Restated — Note 10)		47.8

Balance, December 31, 2006 (As Restated — Note 10)		203.7
Net change in parent advances (unaudited)		(8.5	)
Net income (As Restated — Note 10) (unaudited)		9.5

Balance, March 31, 2007 (As Restated — Note 10) (unaudited)		204.7
Net change in parent advances (unaudited)		(8.6	)
Net income (As Restated — Note 10) (unaudited)		9.3

Balance, June 30, 2007 (As Restated — Note 10) (unaudited)	$	205.4

See accompanying notes to combined financial statements.

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CASH FLOWS

($ in millions)


	Six Months Ended June 30,						Three Months Ended March 31,						Year Ended December 31,
	2007			2006			2007			2006			2006			2005			2004
	(unaudited)						(unaudited)
	(As Restated — Note 10)						(As Restated — Note 10)						(As Restated — Note 10)
OPERATING ACTIVITIES:
Net income	$	18.8		$	28.4		$	9.5		$	13.0		$	47.8		$	57.8		$	37.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		7.9			7.1			3.7			3.5			14.6			14.0			14.4
Deferred income taxes		—			1.8			—			—			1.8			—			—
Other, net		0.1			—			—			—			0.1			0.1			—
Change in operating assets and liabilities which provided (used) cash:
Accounts receivable		5.0			12.7			15.2			3.2			0.3			(16.9	)		2.0
Accounts payable		1.5			(29.1	)		(11.6	)		(21.0	)		(12.6	)		33.1			1.8
Other current assets and liabilities		1.3			(0.3	)		0.2			(0.7	)		(1.0	)		1.8			—
Other non-current assets and liabilities		—			(0.2	)		—			—			(0.2	)		(0.1	)		(0.2	)

Net cash provided by (used in) operating activities		34.6			20.4			17.0			(2.0	)		50.8			89.8			55.0

INVESTING ACTIVITIES:
Capital expenditures		(17.5	)		(7.7	)		(8.5	)		(1.5	)		(12.8	)		(6.1	)		(1.5	)
Proceeds from sales of assets		—			—			—			—			0.1			0.1			—

Net cash used in investing activities		(17.5	)		(7.7	)		(8.5	)		(1.5	)		(12.7	)		(6.0	)		(1.5	)

FINANCING ACTIVITIES:
Net change in parent advances		(17.1	)		(12.7	)		(8.5	)		3.5			(38.1	)		(83.8	)		(53.5	)

Net cash used in financing activities		(17.1	)		(12.7	)		(8.5	)		3.5			(38.1	)		(83.8	)		(53.5	)

Net change in cash		—			—			—			—			—			—			—
Cash, beginning of period		—			—			—			—			—			—			—

Cash, end of period	$	—		$	—		$	—		$	—		$	—		$	—		$	—

See accompanying notes to combined financial statements.

THE EAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS

1.	Description of Business and Basis of Presentation

The East Texas Midstream Business, or the Business, we, our, or us, is engaged in the business of gathering, transporting, treating, compressing, processing, and fractionating natural gas and natural gas liquids, or NGLs. The operations, located near Carthage, Texas, include a natural gas processing complex with a total capacity of 780 million cubic feet per day. The facility is connected to our 845 mile gathering system, as well as third party gathering systems. The complex is adjacent to our Carthage Hub, which delivers residue gas to interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas.

These combined financial statements and related notes present the financial position, results of operations and cash flows, and changes in net parent equity of the Business held by DCP Midstream, LLC and its subsidiaries, or Midstream. Midstream is a joint venture owned 50% by Spectra Energy Corp (which was spun off from Duke Energy Corporation on January 2, 2007) and 50% by ConocoPhillips. Midstream owned a 37% interest, including 100% of the general partner interest, in DCP Midstream Partners, LP, or Partners, prior to this contribution. As of September 28, 2007, Midstream owns a 34% interest, including 100% of the general partner interest, in Partners. Midstream contributed a 25% interest in the Business to Partners, on July 1, 2007. As part of the closing of the contribution, the assets, liabilities and operations of the Business now reside in a new legal entity, DCP East Texas Holdings LLC. Subsequent to the acquisition by Partners, Midstream still directs our business operations. The Business does not currently and is not expected to have any employees. Midstream and its affiliates’ employees are responsible for conducting our business and operating our assets.

The combined financial statements include the accounts of the Business and have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All significant intercompany balances and transactions within the Business have been eliminated. The combined financial statements of the Business have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Business had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising the Business, Midstream’s net investment in the Business is shown as net parent equity, in lieu of owner’s equity, in the combined financial statements. Transactions between the Business and other Midstream operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

The combined statements of operations and cash flows for the six months ended June 30, 2007 and 2006 and for the three months ended March 31, 2007 and 2006, the combined statement of changes in net parent equity for the three months ended June 30, 2007 and March 31, 2007, and the combined balance sheets as of June 30, 2007 and March 31, 2007, are unaudited. These unaudited interim combined financial statements have been prepared in accordance with GAAP. In the opinion of management, the unaudited interim combined financial statements have been prepared on the same basis as the audited combined financial statements, and include all adjustments necessary to present fairly the financial position, and the results of operations and cash flows, for the respective interim periods. Interim financial results are not necessarily indicative of the results to be expected for an annual period.

2.	Summary of Significant Accounting Policies

Use of Estimates — Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

Fair Value of Financial Instruments — The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts, due to the short-term nature of these instruments. Unrealized gains and losses on non-trading derivative instruments are recorded at fair value.

Gas and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the combined balance sheets as accounts receivable — other as of June 30, 2007, March 31, 2007, and December 31, 2006 and 2005, were imbalances totaling $0.2 million (unaudited), $0.1 million (unaudited), $0.4 million and $2.6 million, respectively.

Included in the combined balance sheets as accounts payable — other as of June 30, 2007, March 31, 2007, and December 31, 2006 and 2005, were imbalances totaling $2.2 million (unaudited), $1.7 million (unaudited), $2.2 million and $1.2 million.

Accounting for Risk Management and Derivative Activities and Financial Instruments — Each derivative not qualifying as a normal purchase or normal sale is recorded on a gross basis in the combined balance sheets at its fair value as unrealized gains or unrealized losses on non-trading derivative instruments — affiliates. Derivative assets and liabilities remain classified in the combined balance sheets as unrealized gains or unrealized losses on non-trading derivative instruments — affiliates at fair value until the contractual delivery period impacts earnings.

Our derivative activity includes normal purchase or normal sale contracts, and non-trading derivative instruments related to commodity prices. Normal purchase and normal sale contracts are accounted for under the accrual method and are reflected in the combined statements of operations in either sales or purchases upon settlement. Other commodity non-trading derivative instruments are accounted for under the mark-to-market method, whereby the change in the fair value of the asset or liability is recognized in the combined statements of operations in gains (losses) from non-trading derivative activity — affiliates during the current period.

Valuation — When available, quoted market prices or prices obtained through external sources are used to determine a 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 correlations with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Property, Plant and Equipment — Property, plant and equipment are recorded at historical cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability of a conditional asset retirement obligation as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.

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. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:

•

significant adverse change in legal factors or business climate;

•

a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

•

an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

•

significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;

•

a significant adverse change in the market value of an asset; or

•

a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

Revenue Recognition — We generate the majority of our revenues from gathering, processing, compressing, transporting, and fractionating natural gas and NGLs. We realize revenues either by selling the residue natural gas and NGLs, or by receiving fees from the producers.

We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.

•

Fee-based arrangements — Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase raw natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of raw natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced.

•

Percent-of-proceeds/index arrangements — Under percentage-of-proceeds/index 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/index arrangements correlate directly with the price of natural gas and/or NGLs.

•

Keep-whole arrangements — Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, market the NGLs and return to the producer residue natural gas with a British thermal unit, or Btu, content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.

We recognize revenue for sales and services under the four revenue recognition criteria, as follows:

•

Persuasive evidence of an arrangement exists — Our customary practice is to enter into a written contract, executed by both us and the customer.

•

Delivery — Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

•

The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Collectability is probable — Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.

We generally report revenues gross in the combined statements of operations, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for non-trading derivative activity net in the combined statements of operations as gains (losses) from non-trading derivative activity — affiliates, including mark-to-market gains and losses and financial or physical settlement.

Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of June 30, 2007, March 31, 2007, and December 31, 2006 and 2005, included in the combined balance sheets as other current liabilities, were $0.2 million (unaudited), $0.3 million (unaudited), $0.3 million and $0.1 million, respectively. Environmental liabilities as of December 31, 2005, included in the combined balance sheets as other long-term liabilities, were $0.3 million.

Income Taxes — Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if necessary, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The Business is a member of a consolidated group. We have calculated current and deferred income taxes as if we were a separate taxpayer.

We are treated as a pass-through entity for U.S. federal income tax purposes. As such, we do not directly pay federal income taxes. The Texas legislature replaced their franchise tax with a margin tax system in May 2006. As of 2007, we are subject to the Texas margin tax, which is treated as an income tax. Accordingly, we recorded a deferred tax liability and related expense in 2006, related to the temporary differences that are expected to reverse in periods when the tax will apply.

3.	Recent Accounting Pronouncements

Statement of Financial Accounting Standards, or SFAS, No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115, or SFAS 159 — In February 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our combined results of operations, cash flows or financial position.

SFAS No. 157, Fair Value Measurements, or SFAS 157 — In September 2006, the FASB issued SFAS 157, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our combined results of operations, cash flows or financial position.

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109, or FIN 48 — In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 were effective for us on January 1, 2007, and the adoption of FIN 48 did not have a material impact on our combined results of operations, cash flows or financial position.

Emerging Issues Task Force, or EITF, Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, or EITF 04-13 — In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29, Accounting for Nonmonetary Transactions, or APB 29, when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 is to be applied to new arrangements that we enter into after March 31, 2006. The net impact of the adoption of EITF 04-13 for the year ended December 31, 2006, for the six months ended June 30, 2007, and for the three months ended March 31, 2007 was a reduction of sales and purchases of approximately $44.3 million, $69.2 million (unaudited) and $28.6 million (unaudited), respectively.

4.	Agreements and Transactions with Affiliates

The employees supporting our operations are employees of Midstream. Costs incurred by Midstream on our behalf for salaries and benefits of operating personnel, as well as capital expenditures, maintenance and repair costs, and taxes have been directly allocated to us. Midstream also provides centralized corporate functions on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. Midstream records the accrued liabilities and prepaid expenses for most general and administrative expenses in its financial statements, including liabilities related to payroll, short and long-term incentive plans, employee retirement and medical plans, paid time off, audit, tax, insurance and other service fees. Our share of those costs has been allocated based on Midstream’s proportionate net investment (consisting of property, plant and equipment, net, equity method investment and intangibles) compared to our net investment. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation to us of our costs of doing business borne by Midstream.

We participate in Midstream’s cash management program. As a result, we have no cash balances on the combined balance sheets and all of our cash management activity was performed by Midstream on our behalf, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions with Midstream, which were recorded as parent advances and are included in net parent equity on the accompanying combined balance sheets.

We currently, and anticipate to continue to, sell to Midstream, and purchase from and sell to ConocoPhillips, in the ordinary course of business. Midstream was a significant customer during the six months ended June 30, 2007 and 2006 (unaudited), the three months ended March 31, 2007 and 2006 (unaudited), and the years ended December 31, 2006, 2005 and 2004.

Prior to December 31, 2006, we sold to and purchased from Duke Energy Corporation. On January 2, 2007, Duke Energy Corporation spun off their natural gas businesses, including their 50% ownership interest in Midstream, to Duke Energy shareholders. As a result of this transaction, Duke Energy Corporation’s 50% ownership interest in Midstream was transferred to Spectra Energy Corp. Consequently, Duke Energy Corporation is not considered a related party for reporting periods after January 2, 2007. We had no significant transactions with Spectra Energy Corp.

The following table summarizes transactions with affiliates ($ in millions):


	Six Months Ended June 30,				Three Months Ended March 31,				Year Ended December 31,
	2007		2006		2007		2006		2006		2005		2004
	(unaudited)				(unaudited)
DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate	$	162.9	$	135.0	$	74.0	$	71.8	$	276.3	$	355.2	$	289.2
General and administrative expense	$	6.0	$	4.9	$	2.8	$	2.4	$	11.3	$	9.8	$	8.1
Duke Energy Corporation:
Sales of natural gas, NGLs and condensate	$	—	$	6.6	$	—	$	6.6	$	6.6	$	6.7	$	12.2
Purchases of natural gas and NGLs	$	—	$	0.1	$	—	$	0.1	$	0.1	$	3.8	$	1.6
ConocoPhillips:
Sales of natural gas, NGLs and condensate	$	3.3	$	3.3	$	1.5	$	—	$	3.7	$	3.7	$	6.7
Transportation and processing services	$	0.1	$	0.2	$	0.1	$	0.1	$	0.3	$	0.3	$	0.3
Purchases of natural gas and NGLs	$	1.1	$	5.2	$	0.6	$	4.3	$	9.2	$	21.5	$	2.0

We had accounts receivable and accounts payable with affiliates as follows ($ in millions):


	June 30, 2007		March 31, 2007		December 31,
	June 30, 2007		March 31, 2007		2006		2005
	(unaudited)
Duke Energy Corporation:
Accounts receivable	$	—	$	—	$	—	$	2.4
ConocoPhillips:
Accounts receivable	$	1.1	$	0.2	$	0.1	$	0.1
Accounts payable	$	0.1	$	0.2	$	0.6	$	5.4

5. Property, Plant and Equipment

A summary of property, plant and equipment is as follows ($ in millions):


	Depreciable Life	June 30, 2007			March 31, 2007			December 31,
	Depreciable Life	June 30, 2007			March 31, 2007			2006			2005
		(As Restated — Note 10)
		(unaudited)
Gathering systems	15 — 30 Years	$	72.7		$	71.3		$	70.0		$	59.6
Processing plants	25 — 30 Years		218.5			218.5			218.4			218.1
Transportation	25 — 30 Years		34.2			34.2			34.3			34.2
General plant	3 — 5 Years		7.6			7.3			7.2			6.8
Construction work in progress			18.1			12.6			6.5			2.1

			351.1			343.9			336.4			320.8
Accumulated depreciation			(115.5	)		(111.9	)		(108.1	)		(93.6	)

Property, plant and equipment, net		$	235.6		$	232.0		$	228.3		$	227.2

In addition, property, plant and equipment includes $3.1 million, $0.6 million, and $0.1 million of non-cash additions for the years ended December 31, 2006, 2005 and 2004, respectively, $0 and $0.1 million of non-cash additions for the three months ended March 31, 2007 and 2006, respectively (unaudited), and $0 and $0.2 million of non-cash additions for the six months ended June 30, 2007 and 2006, respectively (unaudited).

6. Risk Management and Derivative Activities, Credit Risk and Financial Instruments

We are exposed to market risks, including changes in commodity prices. We may use financial instruments such as forward contracts, swaps and futures to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. Midstream has a comprehensive risk management policy, or the Risk Management Policy, and a risk management committee, to monitor and manage market risks associated with commodity prices. Midstream’s Risk Management Policy prohibits the use of derivative instruments for speculative purposes.

Commodity Price Risk — Our principal operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and sale of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs and natural gas. As an owner and operator of natural gas processing assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas, NGLs and condensate, and related products produced, processed or transported.

Credit Risk — We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of Midstream, national wholesale marketers, industrial end-users and gas-fired power plants. Our principal NGL customers include an affiliate of Midstream, producers and marketing companies. Concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under Midstream’s corporate credit policy. Midstream’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 Midstream’s 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 Midstream’s credit policy and guidelines. The agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a form satisfactory to us.

Commodity Non-Trading Derivative Activity — The sale of energy related products and services exposes us to the fluctuations in the market values of exchanged instruments. On a monthly basis, we may enter into non-trading derivative instruments in order to match the pricing terms to manage our purchase and sale portfolios. Midstream manages our marketing portfolios in accordance with their Risk Management Policy, which limits exposure to market risk.

7.	Asset Retirement Obligations

Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. Accretion expense for the six months ended June 30, 2007 and 2006 (unaudited), for the three months ended March 31, 2007 and 2006 (unaudited), and the years ended December 31, 2006, 2005 and 2004 was not significant.

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation as of June 30, 2007, March 31, 2007, and December 31, 2006 and 2005, included in the combined balance sheets as other long-term liabilities, was $0.5 million (unaudited), $0.5 million (unaudited), $0.4 million and $0.4 million, respectively.

8.	Income Taxes

In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The tax will be based on the margin earned during the prior calendar year.

The margin has been defined as revenues less cost of goods sold and certain other deductible expenses. The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas.

The Texas margin tax is considered an income tax. GAAP requires that deferred taxes be adjusted upon enactment of new tax law, which occurred in 2006. Accordingly, we recorded a deferred tax liability and related expense of $1.8 million in 2006, related primarily to property, plant and equipment. Beginning in 2007, we are recording current expense for the Texas margin tax.

Our effective tax rate differs from statutory rates primarily due to our being treated as a pass-through entity for United States income tax purposes, while being treated as a taxable entity in Texas.

9.	Commitments and Contingent Liabilities

Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our combined results of operations, financial position, or cash flows.

Insurance — Effective August 2006, Midstream’s insurance coverage is carried with an affiliate of ConocoPhillips and third party insurers. Prior to August 2006, Midstream carried a portion of their insurance coverage with an affiliate of Duke Energy Corporation. Midstream’s insurance coverage includes: (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) excess liability insurance above the established primary limits for commercial general liability and automobile liability insurance; and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, windstorms, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

A portion of the insurance costs described above are allocated by Midstream to us through the allocation methodology described in Note 4.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, or treating natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to

air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our combined results of operations, financial position or cash flows.

10. Restatement

Subsequent to the issuance of our June 30, 2007 combined financial statements in DCP Midstream Partners, LP current report on Form 8-K filed on October 3, 2007, it was determined that expenditures related to a capital project had been improperly expensed to operating and maintenance expense, and should have instead been capitalized in property, plant and equipment, net as they increase the capacity of a gathering and pipeline asset owned by the Business. As a result, it was determined that operating and maintenance expense was overstated and property, plant and equipment, net was understated as of and for the year ended December 31, 2006, as of and for the three months ended March 31, 2007, and as of and for the six months ended June 30, 2007.

The effect of the restatement was as follows as of and for the six months ended June 30, 2007 (Unaudited):


	As Previously Reported			Adjustments			As Restated
Combined Balance Sheet:
Property, plant and equipment, net	$	232.5		$	3.1		$	235.6
Total assets	$	259.3		$	3.1		$	262.4
Net parent equity	$	202.3		$	3.1		$	205.4
Total liabilities and net parent equity	$	259.3		$	3.1		$	262.4

Combined Statement of Operations:
Operating and maintenance expense	$	15.7		$	(2.3	)	$	13.4
Total operating costs and expenses	$	187.8		$	(2.3	)	$	185.5
Operating income	$	16.7		$	2.3		$	19.0
Net income	$	16.5		$	2.3		$	18.8

Combined Statement of Cash Flows:
Net income	$	16.5		$	2.3		$	18.8
Net cash provided by operating activities	$	32.3		$	2.3		$	34.6
Capital expenditures	$	(15.2	)	$	(2.3	)	$	(17.5	)
Net cash used in investing activities	$	(15.2	)	$	(2.3	)	$	(17.5	)

The effect of the restatement was as follows as of and for the three months ended March 31, 2007 (Unaudited):


	As Previously Reported			Adjustments			As Restated
Combined Balance Sheet:
Property, plant and equipment, net	$	230.0		$	2.0		$	232.0
Total assets	$	245.9		$	2.0		$	247.9
Net parent equity	$	202.7		$	2.0		$	204.7
Total liabilities and net parent equity	$	245.9		$	2.0		$	247.9
Combined Statement of Operations:
Operating and maintenance expense	$	7.4		$	(1.2	)	$	6.2
Total operating costs and expenses	$	86.1		$	(1.2	)	$	84.9
Operating income	$	8.3		$	1.2		$	9.5
Net income	$	8.3		$	1.2		$	9.5
Combined Statement of Cash Flows:
Net income	$	8.3		$	1.2		$	9.5
Net cash provided by operating activities	$	15.8		$	1.2		$	17.0
Capital expenditures	$	(7.3	)	$	(1.2	)	$	(8.5	)
Net cash used in investing activities	$	(7.3	)	$	(1.2	)	$	(8.5	)

The effect of the restatement was as follows as of and for the year ended December 31, 2006:


	As Previously Reported			Adjustments			As Restated
Combined Balance Sheet:
Property, plant and equipment, net	$	227.5		$	0.8		$	228.3
Total assets	$	258.6		$	0.8		$	259.4
Net parent equity	$	202.9		$	0.8		$	203.7
Total liabilities and net parent equity	$	258.6		$	0.8		$	259.4
Combined Statement of Operations:
Operating and maintenance expense	$	25.2		$	(0.8	)	$	24.4
Total operating costs and expenses	$	436.6		$	(0.8	)	$	435.8
Operating income	$	48.8		$	0.8		$	49.6
Net income	$	47.0		$	0.8		$	47.8
Combined Statement of Cash Flows:
Net income	$	47.0		$	0.8		$	47.8
Net cash provided by operating activities	$	50.0		$	0.8		$	50.8
Capital expenditures	$	(12.0	)	$	(0.8	)	$	(12.8	)
Net cash used in investing activities	$	(11.9	)	$	(0.8	)	$	(12.7	)

11.

Subsequent Event

On September 28, 2007, DCP East Texas Holdings LLC paid a total distribution of $20.0 million, allocated to the partners in accordance with their respective ownership percentages.

Restated unaudited pro forma condensed consolitated financial statements

Exhibit 99.4

UNAUDITED DCP MIDSTREAM PARTNERS, LP PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

References to we, us or our, refer to DCP Midstream Partners, LP and its consolidated subsidiaries. The unaudited pro forma condensed consolidated financial statements present the impact on our financial position and results of operations of our acquisition from DCP Midstream, LLC, or Midstream, of certain subsidiaries of Momentum Energy Group, Inc., or the MEG Drop Down Transaction, for aggregate consideration of approximately $174.8 million consisting of (1) approximately $153.8 million in cash, and a liability of $9.0 million for net working capital and general and administrative charges, and (2) the issuance of 275,735 common units valued at $12.0 million. The pro forma financial statements also present the impact of the acquisition from Midstream of a 25% limited liability company interest in the East Texas Midstream Business, a 40% limited liability company interest in Discovery Producer Services LLC, or Discovery, and a non-trading derivative instrument, or the Swap, that Midstream entered into in March 2007, or the Midstream Transaction. We paid aggregate consideration of approximately $271.3 million to Midstream, consisting of (1) approximately $243.7 million in cash, including $1.3 million for net working capital and other adjustments, (2) the issuance of 620,404 common units valued at $27.0 million and (3) the issuance of 12,661 general partner equivalent units valued at $0.6 million for the Midstream Transaction. The pro forma financial statements as of June 30, 2007 and March 31, 2007, and for the six months ended June 30, 2007, the three months ended March 31, 2007 and the year ended December 31, 2006, have been prepared based on certain pro forma adjustments to our historical consolidated financial statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2006, and our Quarterly Reports on Form 10-Q for the quarters ended June 30, 2007 and March 31, 2007, as filed with the Securities and Exchange Commission, and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained in those reports. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes thereto.

The unaudited pro forma condensed consolidated balance sheets as of June 30, 2007 and March 31, 2007, have been prepared as if these transactions had occurred on each respective balance sheet date. The unaudited pro forma condensed consolidated statements of operations for the six months ended June 30, 2007, the three months ended March 31, 2007 and the year ended December 31, 2006, have been prepared as if these transactions had occurred on January 1, 2006. Midstream entered into the Swap in March 2007; therefore, the pro forma adjustments related to the Swap only impact the balance sheet as of June 30, 2007 and the statement of operations for the six months ended June 30, 2007. Since these transactions are transactions among entities under common control, the pro forma financial statements are combined on an “as if” pooling basis. Accordingly, the historic impact of the acquired assets and liabilities are carried forward.

The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the transaction as contemplated, and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed consolidated financial statements. The final determination of the MEG Drop Down Transaction working capital amount and allocation of purchase price has not been completed. The accompanying information reflects management’s best estimates.

The unaudited pro forma condensed consolidated financial statements may not be indicative of the results that actually would have occurred if we had owned the assets acquired in these transactions during the periods presented.

Restatement—Subsequent to the issuance of the June 30, 2007 combined financial statements for the East Texas Midstream Business in DCP Midstream Partners, LP current report on Form 8-K filed on October 3, 2007, it was determined that expenditures related to a capital project had been improperly expensed to operating and maintenance expense, and should have instead been capitalized in property, plant and equipment, net as they increase the capacity of a gathering and pipeline asset owned by the East Texas Midstream Business. As a result, it was determined that operating and maintenance expense was overstated by approximately $0.8 million, $1.2 million and $2.3 million for the year ended December 31, 2006, for the three months ended March 31, 2007, and for the six months ended June 30, 2007, respectively, and property, plant and equipment, net was understated by approximately $0.8 million, $2.0 million and $3.1 million as of December 31, 2006, March 31, 2007 and June 30, 2007, respectively. The historical account balances of the East Texas Midstream Business reflect the effects of the restatement.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

JUNE 30, 2007

($ in millions)


	DCP Midstream Partners, LP			The East Texas Midstream Business		Discovery Producer Services LLC		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other			DCP Midstream Partners, LP before MEG			Momentum Energy Group, Inc.		Pro Forma Adjustments - MEG Other			DCP Midstream Partners, LP Pro Forma
				(Restated)				(Restated)			(Restated)											(Restated)
								(a)
ASSETS
Current assets:
Cash and cash equivalents	$	55.0		$	—	$	26.3	$	(26.3	)	$	245.9	(b)	$	57.2		$	20.6	$	120.0	(b)	$	39.0
												(243.7	) (d)							(100.0	) (c)
																				100.0	(e)
																				(5.0	) (d)
																				(153.8	) (d)
Accounts receivable		70.6			26.7		25.3		(52.0	)		—			70.6			19.4		(12.3	) (d)		77.7
Other		33.7			0.1		1.3		(1.4	)		—			33.7			2.5		(0.7	) (d)		35.5

Total current assets		159.3			26.8		52.9		(79.7	)		2.2			161.5			42.5		(51.8	)		152.2
Restricted investments		—			—		6.0		(6.0	)		—			—			—		100.0	(c)		100.0
Property, plant and equipment, net		370.7			235.6		372.8		(608.4	)		—			370.7			249.5		(249.5	) (d)		499.9
																				129.2	(d)
Goodwill and intangible assets, net		44.3			—		—		—			—			44.3			21.0		(21.0	) (d)		108.0
																				63.7	(d)
Equity method investments		6.4			—		—		—			162.0	(d)		168.4			—		—			168.4
Other non-current assets		6.3			—		—		—			—			6.3			0.8		(0.8	) (d)		6.3

Total assets	$	587.0		$	262.4	$	431.7	$	(694.1	)	$	164.2		$	751.2		$	313.8	$	(30.2	)	$	1,034.8


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	92.3		$	49.1	$	22.5	$	(71.6	)	$	—		$	92.3		$	28.5	$	9.0	(d)	$	112.6
																				(17.2	) (d)
Other		12.1			5.6		10.9		(16.5	)		2.4	(d)		14.5			8.3		(1.0	) (d)		21.8
Current maturities of long-term debt		—			—		—		—			—			—			0.7		(0.7	) (d)		—

Total current liabilities		104.4			54.7		33.4		(88.1	)		2.4			106.8			37.5		(9.9	)		134.4
Long-term debt		249.0			—		—		—			245.9	(b)		494.9			22.1		120.0	(b)		614.9
																				(22.1	) (d)
Other long-term liabilities		12.6			2.3		3.9		(6.2	)		6.3	(d)		18.9			3.4		(1.6	) (d)		20.7

Total liabilities		366.0			57.0		37.3		(94.3	)		254.6			620.6			63.0		86.4			770.0

Non-controlling interest in joint venture		—			—		—		—			—			—			22.2		—			22.2
Commitments and contingent liabilities
Partners’ equity:
Members’ capital		—			205.4		394.4		(599.8	)		—			—			—		—			—
Stockholders’ equity		—			—		—		—			—			—			228.6		(228.6	) (d)		—
Common unitholders		349.9			—		—		—			27.0	(d)		258.9			—		12.0	(d)		370.9
												(118.0	) (d)							100.0	(e)
Class C unitholders		(20.7	)		—		—		—			—			(20.7	)		—					(20.7	)
Subordinated unitholders		(102.5	)		—		—		—			—			(102.5	)		—		—			(102.5	)
General partner interest		(5.0	)		—		—		—			0.6	(d)		(4.4	)		—		—			(4.4	)
Accumulated other comprehensive income		(0.5	)		—		—		—			—			(0.5	)		—		—			(0.5	)

Total		221.2			205.4		394.4		(599.8	)		(90.4	)		130.8			228.6		(116.6	)		242.8
Less treasury units		(0.2	)		—		—		—			—			(0.2	)		—		—			(0.2	)

Total partners’ equity		221.0			205.4		394.4		(599.8	)		(90.4	)		130.6			228.6		(116.6	)		242.6

Total liabilities and partners’ equity	$	587.0		$	262.4	$	431.7	$	(694.1	)	$	164.2		$	751.2		$	313.8	$	(30.2	)	$	1,034.8

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

MARCH 31, 2007

($ in millions)


	DCP Midstream Partners, LP			The East Texas Midstream Business		Discovery Producer Services LLC		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other			DCP Midstream Partners, LP Pro Forma
				(Restated)				(Restated)			(Restated)			(Restated)
								(a)
ASSETS
Current assets:
Cash and cash equivalents	$	29.4		$	—	$	30.9	$	(30.9	)	$	245.9	(b)	$	29.4
												(245.9	) (d)
Accounts receivable		68.1			15.8		33.6		(49.4	)		—			68.1
Other		43.1			0.1		3.1		(3.2	)		—			43.1

Total current assets		140.6			15.9		67.6		(83.5	)		—			140.6
Restricted investments		102.0			—		19.9		(19.9	)		—			102.0
Property, plant and equipment, net		193.6			232.0		376.0		(608.0	)		—			193.6
Goodwill and intangible assets, net		32.0			—		—		—			—			32.0
Equity method investments		6.1			—		—		—			167.3	(d)		173.4
Other non-current assets		5.1			—		—		—			0.3	(d)		5.4

Total assets	$	479.4		$	247.9	$	463.5	$	(711.4	)	$	167.6		$	647.0


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	96.4		$	36.1	$	34.8	$	(70.9	)	$	—		$	96.4
Other		8.6			4.8		11.3		(16.1	)		1.5	(d)		10.1

Total current liabilities		105.0			40.9		46.1		(87.0	)		1.5			106.5
Long-term debt		268.0			—		—		—			245.9	(b)		513.9
Other long-term liabilities		5.0			2.3		3.8		(6.1	)		1.7	(d)		6.7

Total liabilities		378.0			43.2		49.9		(93.1	)		249.1			627.1

Commitments and contingent liabilities

Partners’ equity:
Members’ capital		—			—		413.6		(413.6	)		—			—
Predecessor equity		—			204.7		—		(204.7	)		—			—
Common unitholders		226.1			—		—		—			27.0	(d)		144.0
									—			(109.1	) (d)
Class C unitholders		(20.6	)		—		—		—			—			(20.6	)
Subordinated unitholders		(99.6	)		—		—		—			—			(99.6	)
General partner interest		(4.9	)		—		—		—			0.6	(d)		(4.3	)
Accumulated other comprehensive income		0.6			—		—		—			—			0.6

Total		101.6			204.7		413.6		(618.3	)		(81.5	)		20.1
Less treasury units		0.2			—		—		—			—			0.2

Total partners’ equity		101.4			204.7		413.6		(618.3	)		(81.5	)		19.9

Total liabilities and partners’ equity	$	479.4		$	247.9	$	463.5	$	(711.4	)	$	167.6		$	647.0

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2007

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The East Texas Midstream Business			Discovery Producer Services LLC		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other			DCP Midstream Partners, LP before MEG			Momentum Energy Group, Inc.			Pro Forma Adjustments - MEG Other			DCP Midstream Partners, LP Pro Forma
				(Restated)					(Restated)			(Restated)												(Restated)
									(a)
Total operating revenues	$	427.0		$	204.5		$	116.0	$	(320.5	)	$	(8.7	) (f)	$	418.3		$	80.0		$	(28.3	) (d)	$	470.0

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		376.1			157.0			73.4		(230.4	)		—			376.1			50.1			(20.8	) (d)		405.4
Operating and maintenance expense		12.9			13.4			16.3		(29.7	)		—			12.9			7.5			(2.7	) (d)		17.7
Depreciation and amortization expense		7.9			7.9			13.0		(20.9	)		—			7.9			6.8			(2.9	) (d)		15.5
																						3.2	(g)
																						0.5	(h)

General and administrative expense		11.7			7.2			1.1		(8.3	)		—			11.7			5.0			(0.8	) (d)		15.9
Loss on sale of assets		—			—			0.6		(0.6	)		—			—			—			—			—

Total operating costs and expenses		408.6			185.5			104.4		(289.9	)		—			408.6			69.4			(23.5	)		454.5

Operating income		18.4			19.0			11.6		(30.6	)		(8.7	)		9.7			10.6			(4.8	)		15.5
Interest income		2.5			—			1.1		(1.1	)		—			2.5			0.6			(0.3	) (d)		2.8
Interest expense		(8.4	)		—			—		—			(7.1	) (i)		(15.5	)		—			(3.5	) (i)		(19.0	)
Earnings from equity method investments		0.5			—			—		—			7.6	(j)		12.8			—			—			12.8
													4.7	(k)

Other loss		—			—			0.3		(0.3	)		—			—			—			—			—

Income before income taxes		13.0			19.0			13.0		(32.0	)		(3.5	)		9.5			11.2			(8.6	)		12.1
Income tax expense		—			(0.2	)		—		0.2			—			—			(1.5	)		1.5	(d)		—
Non-controlling interest in income		—			—			—		—			—			—			(0.6	)		—			(0.6	)

Net income	$	13.0		$	18.8		$	13.0	$	(31.8	)	$	(3.5	)	$	9.5		$	9.1		$	(7.1	)	$	11.5
Less:
General partner interest in net income		(0.6	)																						(0.6	)

Net income allocable to limited partners	$	12.4																						$	10.9

Net income per limited partner unit — basic and diluted	$	0.60																						$	0.51

Weighted-average limited partner units outstanding — basic and diluted		17.8											0.6									2.7			21.1

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2007

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The East Texas Midstream Business		Discovery Producer Services LLC		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other			DCP Midstream Partners, LP Pro Forma
				(Restated)				(Restated)			(Restated)			(Restated)
								(a)
Total operating revenues	$	240.1		$	94.4	$	52.5	$	(146.9	)	$	(2.9	) (f)	$	237.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		210.9			72.2		33.5		(105.7	)		—			210.9
Operating and maintenance expense		6.6			6.2		6.8		(13.0	)		—			6.6
Depreciation and amortization expense		3.4			3.7		6.5		(10.2	)		—			3.4
General and administrative expense		4.8			2.8		0.5		(3.3	)		—			4.8

Total operating costs and expenses		225.7			84.9		47.3		(132.2	)		—			225.7

Operating income		14.4			9.5		5.2		(14.7	)		(2.9	)		11.5
Interest income		1.7			—		0.7		(0.7	)		—			1.7
Interest expense		(3.8	)		—		—		—			(3.5	) (i)		(7.3	)
Earnings from equity method investments		0.2			—		—		—			3.8	(j)		6.4
												2.4	(k)
Other income		—			—		0.7		(0.7	)		—			—

Net income	$	12.5		$	9.5	$	6.6	$	(16.1	)	$	(0.2	)	$	12.3
Less:
General partner interest in net income		(0.3	)									—			(0.3	)

Net income allocable to limited partners	$	12.2									$	(0.2	)	$	12.0

Net income per limited partner unit — basic and diluted	$	0.58												$	0.57

Weighted-average limited partner units outstanding — basic and diluted		17.7										0.6			18.3

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2006

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The East Texas Midstream Business			Discovery Producer Services LLC		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other			DCP Midstream Partners, LP before MEG			Momentum Energy Group, Inc.			Pro Forma Adjustments - MEG Other			DCP Midstream Partners, LP Pro Forma
				(Restated)					(Restated)			(Restated)												(Restated)
									(a)
Total operating revenues	$	795.8		$	485.4		$	197.3	$	(682.7	)	$	—		$	795.8		$	65.5		$	(18.1	) (d)	$	843.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		700.4			385.3			119.6		(504.9	)		—			700.4			45.6			(12.2	) (d)		733.8
Operating and maintenance expense		23.7			24.4			24.1		(48.5	)		—			23.7			7.1			(2.7	) (d)		28.1
Depreciation and amortization expense		12.8			14.6			25.6		(40.2	)		—			12.8			5.5			(2.7	) (d)		22.9
																						6.4	(g)
																						0.9	(h)
General and administrative expense		21.0			11.5			2.4		(13.9	)		—			21.0			6.3			(1.1	) (d)		26.2
Gain on sale of assets		—			—			—		—			—			—			(4.7	)		4.7	(d)		—

Total operating costs and expenses		757.9			435.8			171.7		(607.5	)		—			757.9			59.8			(6.7	)		811.0

Operating income		37.9			49.6			25.6		(75.2	)		—			37.9			5.7			(11.4	)		32.2
Interest income		6.3			—			2.4		(2.4	)		—			6.3			1.0			(0.8	) (d)		6.5
Interest expense		(11.5	)		—			—		—			(14.0	) (i)		(25.5	)		—			(6.9	) (i)		(32.4	)
Earnings from equity method investments		0.3			—			—		—			16.9	(j)		29.2			—			—			29.2
													12.0	(k)

Other income		—			—			2.1		(2.1	)		—			—			—			—			—

Income before income taxes		33.0			49.6			30.1		(79.7	)		14.9			47.9			6.7			(19.1	)		35.5
Income tax expense		—			(1.8	)		—		1.8			—			—			—			—			—
Non-controlling interest in loss		—			—			—		—			—			—			0.1			—			0.1

Net income	$	33.0		$	47.8		$	30.1	$	(77.9	)	$	14.9		$	47.9		$	6.8		$	(19.1	)	$	35.6
Less:
Net loss attributable to predecessor operations		2.3																							2.3
General partner interest in net income		(0.7	)																						(0.8	)

Net income allocable to limited partners	$	34.6																						$	37.1

Net income per limited partner unit — basic and diluted	$	1.90																						$	1.76

Weighted-average limited partner units outstanding — basic and diluted		17.5											0.6									2.7			20.8

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

NOTES TO UNAUDITED DCP MIDSTREAM PARTNERS, LP

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to DCP Midstream Partners, LP, or Partners. The historical financial information is derived from our historical consolidated financial statements, and the historical financial statements of Momentum Energy Group, Inc., or Momentum, the East Texas Midstream Business and Discovery Producer Services LLC, or Discovery. The pro forma adjustments for the balance sheet as of June 30, 2007 and the statements of operations for the six months ended June 30, 2007 and the year ended December 31, 2006, have been prepared as if we acquired certain subsidiaries of Momentum Energy Group, Inc., or the MEG Drop Down Transaction, and a 25% limited liability company interest in the East Texas Midstream Business, a 40% limited liability company interest in Discovery, and the Swap, or the Midstream Transaction, on June 30, 2007, for the balance sheet, and on January 1, 2006, for the statements of operations. The pro forma adjustments for the balance sheet as of March 31, 2007 and the statement of operations for the three months ended March 31, 2007, have been prepared as if we acquired a 25% limited liability company interest in the East Texas Midstream Business, a 40% limited liability company interest in Discovery, and the Swap, or the Midstream Transaction, on March 31, 2007, for the balance sheet, and on January 1, 2007, for the statement of operations. Midstream entered into the Swap in March 2007; therefore, the pro forma adjustments related to the Swap only impact the balance sheets as of June 30, 2007 and March 31, 2007 and the statements of operations for the six months ended June 30, 2007 and the three months ended March 31, 2007. Since the Midstream Transaction is a transaction among entities under common control, the pro forma financial statements are combined on an “as if” pooling basis. Accordingly, the historic cost of the acquired assets and liabilities in the Midstream Transaction are carried forward.

The pro forma condensed consolidated financial statements reflect the following transactions:

The MEG Drop Down Transaction:

•

the cash proceeds to us from the issuance of 2,380,952 common limited partner units for $100.0 million under a private placement;

•

the purchase of $100.0 million of collateral assets and the borrowing of $100 million under our term loan facility;

•

the borrowing of $20.0 million under our revolving credit facility;

•

the acquisition of certain subsidiaries of Momentum Energy Group, Inc.; and

•

the aggregate consideration paid to Midstream, consisting of approximately (1) $153.8 million in cash, (2) a liability of $9.0 million for net working capital and general and administrative charges, and (3) the issuance of 275,735 common limited partner units valued at $12.0 million.

The Midstream Transaction:

•

the borrowing of $245.9 million under our existing credit facility to finance the acquisition;

•

the acquisition of the 25% interest in the East Texas Midstream Business and 100% of Midstream’s 40% interest in Discovery;

•

the acquisition of the Swap. In March 2007, Midstream entered into a crude oil swap, a non-trading derivative, to mitigate a portion of the price risk from July 2007 through December 2012. The Swap is for a total of approximately 1.9 million barrels of crude oil at $66.72 per barrel; and

•

the aggregate consideration paid to Midstream, consisting of approximately $243.7 million in cash, including $1.3 million for net working capital and other adjustments, and the issuance of 620,404 common units and 12,661 general partner equivalent units.

Partners’ omnibus services agreement with Midstream increased by $1.6 million annually as a result of the MEG Drop Down Transaction and increased $0.2 million annually as a result of the Midstream Transaction, for incremental general and administrative expenses, subject to annual increases in the Consumer Price Index.

Note 2. Pro Forma Adjustments and Assumptions

(a)

Reflects adjustments to eliminate 100% of the activity of the East Texas Midstream Business and Discovery, as Partners will account for these investments under the equity method.

(b)

Reflects proceeds to us from borrowings under our revolving credit facility of $245.9 million for the Midstream Transaction, and borrowings under our revolving credit facility of $20.0 million and under our term loan facility of $100.0 million for the MEG Drop Down Transaction.

(c)

Reflects the purchase of collateral assets of $100.0 million with cash received from the $100.0 million of borrowings under our term loan facility.

(d)

Reflects the MEG Drop Down Transaction and the Midstream Transaction, along with the related distributions to Midstream of the aggregate consideration. These acquisitions will be recorded at Midstream’s cost as they are considered transactions among entities under common control. The consideration was allocated as follows, subject to customary purchase price adjustments ($ in millions):

Midstream Transaction:


	June 30, 2007			March 31, 2007
Cash consideration	$	243.7		$	245.9
Common units		27.0			27.0
General partner equivalent units		0.6			0.6

Aggregate consideration		271.3			273.5
Historical cost of interest in the East Texas Midstream Business		(51.4	)		(51.2	)
Historical cost of interest in Discovery		(110.6	)		(116.1	)
Historical cost of the Swap		8.7			2.9

Adjustment to net parent equity for excess consideration	$	118.0		$	109.1

The historical cost of the interest in Discovery includes the net difference between the carrying amount of Discovery and the underlying equity of Discovery, or the Outside Basis. As of June 30, 2007 and March 31, 2007, the Outside Basis in Discovery was a deficit of $46.1 million and $47.4 million, respectively.

The historical cost of the Swap as of June 30, 2007 consists of a current liability of $2.4 million and a long-term liability of $6.3 million, and as of March 31, 2007 consists of a non-current asset of $0.3 million, a current liability of $1.5 million and a long-term liability of $1.7 million.

The adjustment to net parent equity was allocated to the common units. The value of the common units and general partner equivalent units above was based on the average market value of Partners’ common units for the ten days prior to the announcement of this transaction.

MEG Drop Down Transaction:


Cash consideration	$	153.8
Liability for net working capital and general and administrative expenses		9.0
Common limited partner units		12.0

Aggregate consideration	$	174.8

The purchase price was allocated as follows:
Cash	$	15.6
Accounts receivable		7.1
Other current assets		1.8
Property, plant and equipment		129.2
Goodwill and intangible assets		63.7
Accounts payable		(11.3	)
Other current liabilities		(7.3	)
Other long-term liabilities		(1.8	)
Non-controlling interest in joint venture		(22.2	)

Total purchase price allocation	$	174.8

The acquisition of MEG was accounted for by Midstream under the purchase method of accounting. Midstream’s purchase price allocation was based on the estimated fair values of the assets acquired, including the fair values of identifiable intangible assets as of August 29, 2007, the date that the acquisition was consummated. Our acquisition of certain subsidiaries of MEG from Midstream constitutes the acquisition of a business and was recognized at Midstream’s basis. The pro forma allocation of purchase price is preliminary and subject to adjustments. Adjustments could result from revisions to the purchase price, as provided in the Contribution and Sale Agreement, working capital adjustments, and the allocation of $192.9 million between property, plant and equipment and intangible assets based on valuations to be provided by an independent third party. The pro forma adjustments also reflect the portion of MEG retained by Midstream.

(e)

Reflects proceeds to us of $100.0 million from the sale of 2,380,952 common units, in connection with the MEG Transaction.

(f)

Reflects losses from non-trading derivative activity associated with the acquisition of the Swap.

(g)

Represents depreciation of fixed assets acquired in the MEG Transaction.

(h)

Represents amortization of intangibles acquired in the MEG Transaction.

(i)

Reflects the increase in interest expense associated with the incremental debt for the acquisition described in (b) above. The following presents the weighted average interest rates and pro forma long-term debt used to calculate the increase in interest expense for the respective periods ($ in millions):


			Pro Forma Long-Term Debt
	Weighted Average Interest Rate		Midstream Transaction		MEG Drop Down Transaction
Six months ended June 30, 2007	5.77	%	$	245.9	$	120.0
Three months ended March 31, 2007	5.71	%	$	245.9		N/A
Year ended December 31, 2006	5.71	%	$	245.9	$	120.0

As of June 30, 2007 , the effect of a 0.125% variance in interest rates on pro forma interest expense would have been approximately $0.5 million annually.

(j)

Reflects the increase in earnings from equity method investments associated with the acquisition of a 40% limited liability company interest in Discovery. The increase in earnings from equity method investments includes amortization of the Outside Basis in Discovery. The following presents the increase in earnings from equity method investments for the respective periods ($ in millions):


	Six Months Ended June 30, 2007		Three Months Ended March 31, 2007		Year Ended December 31, 2006
Our share of Discovery’s historical net income	$	5.2	$	2.6	$	12.0
Amortization of the Outside Basis		2.4		1.2		4.9

Increase in earnings from equity method investments	$	7.6	$	3.8	$	16.9

(k)

Reflects the increase in earnings from equity method investments associated with the acquisition of a 25% limited liability company interest in the East Texas Midstream Business.

Note 3. Pro Forma Net Income Per Limited Partner Unit

Our net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds certain distribution levels, it will have the impact of reducing net income per limited partner unit, or LPU. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income per unit does not exceed certain distribution levels, there is no impact on our calculation of earnings per LPU. For the six months ended June 30, 2007, the three months ended March 31, 2007 and the year ended December 31, 2006, our pro forma aggregate net income per unit exceeded certain distribution levels, and as a result we allocated $0.2 million, $1.6 million and $0.5 million, respectively, in additional earnings to the general partner.

Basic and diluted net income per LPU is calculated by dividing limited partners’ interest in pro forma net income, less pro forma general partner incentive distributions as described above, by the pro forma weighted average number of outstanding LPUs during the period, assuming each of the following were outstanding since January 1, 2006:

•

275,735 common units issued in connection with the MEG Drop Down transaction (these units were not assumed outstanding for the statement of operations for the three months ended March 31, 2007);

•

2,380,952 common units issued in connection with a private placement; and

•

620,404 common units issued in connection with the Midstream transaction.

The following table illustrates our calculation of pro forma net income per LPU ($ in millions, except per unit amounts):


	Six Months Ended June 30, 2007			Three Months Ended March 31 2007			Year Ended December 31, 2006
Pro forma net income	$	11.5		$	12.3		$	35.6
Less: net loss attributable to predecessor operations		—			—			2.3

Pro forma net income attributable to partnership		11.5			12.3			37.9
Less: general partner interest in net income		(0.6	)		(0.3	)		(0.8	)

Pro forma limited partners’ interest in net income		10.9			12.0			37.1
Less: additional earnings allocated to general partner		(0.2	)		(1.6	)		(0.5	)

Pro forma net income available to limited partners	$	10.7		$	10.4		$	36.6

Pro forma net income per LPU—basic and diluted	$	0.51		$	0.57		$	1.76