SEC Filing | DCP Midstream, LP

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Form 8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

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 3, 2007 (July 1, 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))

This Amendment No. 1 to the Current Report on Form 8-K is filed as an amendment (“Amendment No. 1”) 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 and September 5, 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. 1 is being filed to update the financial information included in the July 2, 2007 Form 8-K through June 30, 2007, and to include the financial information required under Item 9.01 that was omitted from the September 5, 2007 Form 8-K.

Item 9.01

Financial Statements and Exhibits.

(a)

Financial statements of businesses acquired.

Audited consolidated financial statements of Discovery Producer Services LLC as of December 31, 2006 and 2005, and for the years ended December 31, 2006, 2005 and 2004, and unaudited consolidated financial statements of Discovery Producer Services LLC as of June 30, 2007, and for the six months ended June 30, 2007 and 2006, are attached hereto as Exhibit 99.1, and are incorporated herein by reference.

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

Audited consolidated financial statements of Momentum Energy Group, Inc. and Subsidiaries as of June 30, 2007, and December 31, 2006 and 2005, and for the six month period ended June 30, 2007, for the years ended December 31, 2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004, and unaudited consolidated financial statements of Momentum Energy Group, Inc. and Subsidiaries for the six months ended June 30, 2006, are attached hereto as Exhibit 99.3, 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, and for the six months ended June 30, 2007, and for the year ended December 31, 2006, 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 on July 2, 2007 by DCP.

(c)

Not applicable.

(d)

Exhibits.

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 3, 2007		/s/ Thomas E. Long
		Name: Thomas E. Long
		Title: Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

Exhibit 23.1		Consent of Ernst & Young LLP on Discovery Producer Services LLC’s Consolidated Financial Statements as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004.

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 23.3		Consent of Deloitte & Touche LLP on Momentum Energy Group, Inc. and Subsidiaries Consolidated Financial Statements as of June 30, 2007, and December 31, 2006 and 2005 and for the six months ended June 30, 2007, and the years ended December 31, 2006 and 2005 and the period from August 24, 2004 through December 31, 2004.

Exhibit 99.1		Audited and unaudited historical consolidated financial statements of Discovery Producer Services LLC.

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

Exhibit 99.3		Audited and unaudited historical consolidated financial statements of Momentum Energy Group, Inc. and Subsidiaries.

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

Consent of Ernst & Young LLP on Discovery Producer Services LLC

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement on Form S-8 (No. 333-142271) of DCP Midstream Partners, LP of our report dated March 5, 2007, with respect to the consolidated financial statements of Discovery Producer Services LLC, included in the Current Report (Form 8-K/A) dated October 3, 2007, filed with the Securities and Exchange Commission.


		/s/ Ernst & Young LLP

		Tulsa, Oklahoma
		September 27, 2007

Consent of Deloitte & Touche LLP on East Texas Midstream Business

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, (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 this Current Report on Form 8-K/A under the Securities and Exchange Act of 1934.

/s/ Deloitte & Touche LLP

Denver, Colorado

October 3, 2007

Consent of Deloitte & Touche LLP on Momentum Energy Group, Inc.

Exhibit 23.3

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 August 22, 2007, relating to the consolidated financial statements of Momentum Energy Group, Inc. and Subsidiaries as of June 30, 2007, December 31, 2006 and 2005 and for the six month period ended June 30, 2007, the years ended December 31, 2006 and 2005, and the for the period August 24, 2004 (date of inception) through December 31, 2004 appearing in this Current Report on Form 8-K/A under the Securities and Exchange Act of 1934.

/s/ Deloitte & Touche LLP

Houston, Texas

October 3, 2007

Historical Consolidated Financial Statements of Discovery

Exhibit 99.1

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2007 (UNAUDITED) AND DECEMBER 31, 2006 AND 2005, AND

FOR THE PERIODS ENDED JUNE 30, 2007 AND 2006 (UNAUDITED), AND DECEMBER 31, 2006, 2005 AND 2004

Report of Independent Registered Public Accounting Firm

To the Management Committee of

Discovery Producer Services LLC

We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as of December 31, 2006 and 2005, and the related consolidated statements of income, members’ capital, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Discovery Producer Services LLC at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

March 5, 2007

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED BALANCE SHEETS


	(In thousands)
	June 30, 2007		December 31,
	June 30, 2007		2006		2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	26,333	$	37,583	$	21,378
Trade accounts receivable:
Affiliate		14,903		11,986		31,448
Other		5,739		6,838		13,975
Insurance receivable		4,703		12,623		476
Inventory		837		576		924
Other current assets		463		4,235		2,324

Total current assets		52,978		73,841		70,525

Restricted cash		5,955		28,773		44,559
Property, plant, and equipment, net		372,770		355,304		344,743

Total assets	$	431,703	$	457,918	$	459,827


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable:
Affiliate	$	6,503	$	7,017	$	12,970
Other		15,989		23,618		23,160
Accrued liabilities		5,992		5,119		6,205
Other current liabilities		4,936		4,805		2,735

Total current liabilities		33,420		40,559		45,070

Noncurrent accrued liabilities		3,894		3,728		1,121
Commitments and contingent liabilities (Note 7)
Members’ capital		394,389		413,631		413,636

Total liabilities and members’ capital	$	431,703	$	457,918	$	459,827

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF INCOME


	(In thousands)
	Six Months Ended June 30,						Years Ended December 31,
	2007			2006			2006			2005			2004
	(Unaudited)
Revenues:
Product sales:
Affiliate	$	90,805		$	66,266		$	148,385		$	70,848		$	57,838
Third-party		5,251			—			—			4,271			1,611
Gas and condensate transportation services:
Affiliate		591			2,880			3,835			2,104			3,966
Third-party		7,850			7,504			14,668			13,302			12,052
Gathering and processing services:
Affiliate		1,772			6,091			8,605			3,912			6,962
Third-party		9,223			10,740			19,473			25,806			14,168
Other revenues		493			1,555			2,347			2,502			3,279

Total revenues		115,985			95,036			197,313			122,745			99,876
Costs and expenses:
Product cost and shrink replacement:
Affiliate		43,424			37,779			66,890			19,103			423
Third-party		29,983			19,669			52,662			45,364			44,932
Operating and maintenance expenses:
Affiliate		2,625			2,121			5,276			3,739			3,098
Third-party		12,889			7,933			17,773			6,426			14,756
Depreciation and accretion		12,991			12,753			25,562			24,794			22,795
Taxes other than income		699			556			1,114			1,151			1,382
General and administrative expenses — affiliate		1,123			1,234			2,150			2,053			1,424
Other (income) expense, net		(28	)		292			283			(33	)		(54	)
Loss on the sale of property, plant, and equipment		603			—			—			—			—

Total costs and expenses		104,309			82,337			171,710			102,597			88,756

Operating income		11,676			12,699			25,603			20,148			11,120
Interest income		(1,083	)		(1,227	)		(2,404	)		(1,685	)		(550	)
Foreign exchange (gain) loss		(252	)		(1,394	)		(2,076	)		1,005			—

Income before cumulative effect of change in accounting principle		13,011			15,320			30,083			20,828			11,670
Cumulative effect of change in accounting principle		—			—			—			(176	)		—

Net income	$	13,011		$	15,320		$	30,083		$	20,652		$	11,670

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENT OF MEMBERS' CAPITAL


	Williams Energy, L.L.C.			Williams Partners Operating L.L.C.			DCP Midstream, LLC			Eni BB Pipelines LLC			Total
	(In thousands)
Balance at December 31, 2003	$	189,987		$	—		$	126,650		$	63,338		$	379,975
Net income		5,835			—			3,890			1,945			11,670

Balance at December 31, 2004		195,822			—			130,540			65,283			391,645
Contributions		16,269			24,400			7,634			—			48,303
Distributions		(30,030	)		(1,280	)		(15,654	)		—			(46,964	)
Net income		8,063			4,651			6,909			1,029			20,652
Sale of Eni 16.67% interest to Williams Energy L.L.C.		66,312			—			—			(66,312	)		—
Sale of Williams Energy, L.L.C.'s 40% interest to Williams Partners Operating L.L.C.		(142,761	)		142,761			—			—			—
Sale of Williams Energy, L.L.C.'s 6.67% interest to DCP Midstream, LLC		(25,869	)		—			25,869			—			—

Balance, December 31, 2005		87,806			170,532			155,298			—			413,636
Contributions		800			1,600			11,109			—			13,509
Distributions		(10,798	)		(16,400	)		(16,400	)		—			(43,598	)
Net income		6,017			12,033			12,033			—			30,083

Balance at December 31, 2006		83,825			167,765			162,040			—			413,630
Contributions (unaudited)		—			—			3,920			—			3,920
Distributions (unaudited)		(7,234	)		(14,469	)		(14,469	)		—			(36,172	)
Net income (unaudited)		2,603			5,204			5,204			—			13,011
Sale of Williams Energy, L.L.C.’s 20% interest to Williams Partners Operating L.L.C.		(79,194	)		79,194			—			—			—

Balance at June 30, 2007 (unaudited)	$	—		$	237,694		$	156,695		$	—		$	394,389

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS


	(In thousands)
	Six Months Ended June 30,						Years Ended December 31,
	2007			2006			2006			2005			2004
	(Unaudited)
OPERATING ACTIVITIES:
Net income	$	13,011		$	15,320		$	30,083		$	20,652		$	11,670
Cumulative effect of change in accounting principle		—			—			—			176			—
Adjustments to reconcile to cash provided by operations:
Depreciation and accretion		12,991			12,753			25,562			24,794			22,795
Loss on the sale of property, plant and equipment		603			—			—			—			—
Cash provided (used) by changes in assets and liabilities:
Trade accounts receivable		(1,818	)		32,662			26,599			(35,263	)		(1,658	)
Insurance receivable		7,920			(5,090	)		(12,147	)		(476	)		—
Inventory		(261	)		208			348			(84	)		(240	)
Other current assets		3,772			781			(1,911	)		(1,012	)		(1	)
Accounts payable		(11,083	)		(23,744	)		(6,062	)		29,355			1,256
Accrued liabilities		131			(1,360	)		(1,086	)		(7,992	)		2,469
Other current liabilities		873			(257	)		2,070			664			(668	)

Net cash provided by operating activities		26,139			31,273			63,456			30,814			35,623

INVESTING ACTIVITIES:
Decrease (increase) in restricted cash		22,818			12,050			15,786			(44,559	)		—
Property, plant, and equipment:
Capital expenditures		(31,544	)		(22,260	)		(33,516	)		(12,906	)		(46,701	)
Proceeds from sale of property, plant and equipment		649			—			—			—			—
Change in accounts payable — capital expenditures		2,940			1,163			568			(8,532	)		7,586

Net cash provided (used) by investing activities		(5,137	)		(9,047	)		(17,162	)		(65,997	)		(39,115	)

FINANCING ACTIVITIES:
Distributions to members		(36,172	)		(22,598	)		(43,598	)		(46,964	)		—
Capital contributions		3,920			7,383			13,509			48,303			—

Net cash provided (used) by financing activities		(32,252	)		(15,215	)		(30,089	)		1,339			—

Increase (decrease) in cash and cash equivalents		(11,250	)		7,011			16,205			(33,844	)		(3,492	)
Cash and cash equivalents at beginning of period		37,583			21,378			21,378			55,222			58,714

Cash and cash equivalents at end of period	$	26,333		$	28,389		$	37,583		$	21,378		$	55,222

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 1. Organization and Description of Business

Our company consists of Discovery Producer Services LLC (“DPS”), a Delaware limited liability company formed on June 24, 1996, and its wholly owned subsidiary, Discovery Gas Transmission LLC (“DGT”), a Delaware limited liability company formed on June 24, 1996. DPS was formed for the purpose of constructing and operating a 600 million cubic feet per day (“MMcf/d”) cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day (“bpd”) natural gas liquids fractionator plant near Paradis, Louisiana. DGT was formed for the purpose of constructing and operating a natural gas pipeline from offshore deep water in the Gulf of Mexico to DPS’s gas processing plant in Larose, Louisiana. The pipeline has a design capacity of 600 MMcf/d and consists of approximately 173 miles of pipe. DPS has since connected several laterals to the DGT pipeline to expand its presence in the Gulf. Herein, DPS and DGT are collectively referred to in the first person as “we,” “us” or “our” and sometimes as “the Company”.

Until April 14, 2005, we were owned 50% by Williams Energy, L.L.C. (a wholly owned subsidiary of The Williams Companies, Inc.), 33.33% by DCP Midstream, LLC (“DCP Midstream”), formerly Duke Energy Field Services, LLC and 16.67% by Eni BB Pipeline, LLC (“Eni”). Williams Energy, L.L.C is our operator. Herein, The Williams Companies, Inc. and its subsidiaries are collectively referred to as “Williams.”

On April 14, 2005, Williams acquired the 16.67% ownership interest in us, which was previously held by Eni. As a result, we became 66.67% owned by Williams and 33.33% owned by DCP Midstream.

On August 22, 2005, we distributed cash of $44 million to the members based on 66.67% ownership by Williams and 33.33% ownership by DCP Midstream.

On August 23, 2005, Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners L.P.) (“WPZ”) acquired a 40% interest in us, which was previously held by Williams. As a result, we became 40% owned by WPZ, 26.67% owned by Williams and 33.33% owned by DCP Midstream. In connection with this acquisition, Williams, DCP Midstream and WPZ amended our limited liability company agreement including provisions for (1) quarterly distributions of available cash, as defined in the amended agreement and (2) pursuit of capital projects for the benefit of one or more of our members when there is not unanimous consent.

On December 22, 2005, DCP Midstream acquired a 6.67% interest in us, which was previously held by Williams. As a result, we became 40% owned by WPZ, 20% owned by Williams and 40% owned by DCP Midstream.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of DPS and its wholly owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated. The accompanying unaudited interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2007, and the results of operations and cash flows for the six months ended June 30, 2006 and 2007.

Reclassifications. Certain prior years amounts have been reclassified to conform with the current year presentation. Certain revenues, expenses, and liabilities for the year ended December 31, 2006 have been reclassified as affiliate transactions due to the affiliate relationship with DCP Midstream. Capitalized labor and projects fees for 2006 were also reclassified. See Note 3.

Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions used in the calculation of asset retirement obligations are, in the opinion of management, significant to the underlying amounts included in the consolidated financial statements. It is reasonably possible that future events or information could change those estimates.

Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of the customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. There was no allowance for doubtful accounts at December 31, 2006 and 2005.

Insurance Receivable. Expenditures incurred for the repair of the pipeline and onshore facilities damaged by Hurricane Katrina in 2005, which are probable of recovery when incurred, are recorded as insurance receivable. Expenditures up to the insurance deductible and amounts subsequently determined not to be recoverable are expensed.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 2. Summary of Significant Accounting Policies (continued)

Gas Imbalances. In the course of providing transportation services to customers, DGT may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables which are recovered or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the future. Imbalance receivables and payables are included in Other current assets and Other current liabilities in the Consolidated Balance Sheets. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and the timing of delivery of gas based on operational conditions. In accordance with its tariff, DGT is required to account for this imbalance (cash-out) liability/receivable and refund or invoice the excess or deficiency when the cumulative amount exceeds $400,000. To the extent that this difference, at any year end, is less than $400,000, such amount would carry forward and be included in the cumulative computation of the difference evaluated at the following year end.

Inventory. Inventory includes fractionated products at our Paradis facility and is carried at the lower of cost or market.

Restricted Cash. Restricted cash within non-current assets relates to escrow funds contributed by our members for the construction of the Tahiti pipeline lateral expansion. The restricted cash is classified as non-current because the funds will be used to construct a long-term asset. The restricted cash is primarily invested in short-term money market accounts with financials institutions.

Property, Plant, and Equipment. Property, plant, and equipment are carried at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant, and equipment.

Depreciation of DPS’s facilities and equipment is computed primarily using the straight-line method with 25-year lives. Depreciation of DGT’s facilities and equipment is computed using the straight-line method with 15-year lives.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (“ARO”). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in operating income.

Revenue Recognition. Revenue for sales of products are recognized in the period of delivery and revenues from the gathering, transportation and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes. DGT is subject to Federal Energy Regulatory Commission (“FERC”) regulations, and accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering regulatory proceedings by DGT and other third parties, advice of counsel, and estimated total exposure as discounted and risk weighted, as well as collection and other risks. There was no rate refund liabilities accrued at December 31, 2006 or 2005.

Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an individual asset or asset group basis when events or changes in circumstances indicates that, in our management’s judgment, the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Accounting for Repair and Maintenance Costs. We expense the cost of maintenance and repairs as incurred. Expenditures that enhance the functionality or extend the useful lives of the assets are capitalized and depreciated over the remaining useful life of the asset.

Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial statements.

Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains or losses which are reflected in the Consolidated Statements of Income.

Recent Accounting Standards. In January 2006, Williams adopted Statement of Financial Accounting Standard (“SFAS”) No. 123, “Share-Based Payment.” Accordingly payroll costs directly charged to us by Williams and general and administrative costs allocated to us by Williams (see Note 3) include such compensation costs beginning January 1, 2006. The cost is charged to us through specific allocations of certain employees if they directly support our operations. Our adoption of this Statement did not have a material impact on our Consolidated Financial Statements.

In January 2006, we adopted SFAS No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4.” The Statement amends Accounting Research Bulletin (“ARB”) No. 43, Chapter 4, “Inventory Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. Our adoption of this Statement did not have a material impact on our Consolidated Financial Statements.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 2. Summary of Significant Accounting Policies (continued)

In January 2006, we adopted SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29.” The Statement amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The impact of this Statement on our Financial Statements was not material.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. We will assess the impact of this Statement on our Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115”. SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. We will not adopt SFAS No. 159 prior to January 1, 2008. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. We continue to assess whether to apply the provisions of SFAS No. 159 to eligible financial instruments in place on the adoption date and the related impact on our Consolidated Financial Statements.

Note 3. Related Party Transactions

We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with Williams. Under these agreements, we reimburse Williams for direct payroll and employee benefit costs incurred on our behalf. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Additionally, we purchase a portion of the natural gas from Williams to meet our fuel and shrink requirements at our processing plant. These purchases are made at market rates at the time of purchase. These costs are included in Operating and maintenance expenses — affiliate and Product costs and shrink replacement — affiliate on the Consolidated Statements of Income. Also included in our Operating and maintenance expenses — affiliate is rental expense resulting from a 10 year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP (DCP Midstream’s affiliate), as part of our Market Expansion project which began in June 2005.

We pay Williams a monthly operation and management fee to cover the cost of accounting services, computer systems and management services provided to us. This fee is presented as General and administrative expenses—affiliate on the Consolidated Statements of Income.

We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and is capitalized as part of the construction costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows:


	For the Six Months Ended June 30,
	For the Six Months Ended June 30,				Years Ended December 31,
	2007		2006		2006		2005		2004
					*(In thousands)*
Capitalized labor	$	121	$	206	$	373	$	115	$	288
Capitalized project fee		697		373		538		351		854

	$	818	$	579	$	911	$	466	$	1,142

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 3. Related Party Transactions (continued)

We have various business transactions with our members and other subsidiaries and affiliates of our members. We sell the NGLs to which we take title and excess gas to Williams. Revenues associated with these activities are reflected as Product sales — affiliate on the Consolidated Statements of Income. These transactions are conducted at current market prices for the products. In 2006, we had transactions with DCP Midstream’s affiliate, Texas Eastern Corporation. During 2005, we had transactions with DCP Midstream’s affiliates, Texas Eastern Corporation and ConocoPhillips Company. These transactions primarily included processing and sales of natural gas liquids and transportation of gas and condensate. We have business transactions with Eni that primarily include processing and transportation of gas and condensate. The following table summarizes these related-party revenues during 2006, 2005 and 2004.


	Years Ended December 31,
	2006		2005		2004
	*(In thousands)*
Williams	$	148,543	$	70,848	$	57,838
Texas Eastern Corporation		12,282		2,663		—
Eni*		—		2,830		10,928
ConocoPhillips		—		523		—

Total	$	160,825	$	76,864	$	68,766

*	Through April 14, 2005

Note 4. Property, Plant, and Equipment

Property, plant, and equipment consisted of the following at December 31, 2006 and 2005:


	Years Ended December 31,
	2006		2005
	*(In thousands)*
Property, plant, and equipment:
Construction work in progress	$	37,259	$	5,444
Buildings		4,434		4,406
Land and land rights		2,491		1,530
Transportation lines		303,283		302,252
Plant and other equipment		200,990		198,837

Total property, plant, and equipment		548,457		512,469
Less accumulated depreciation		193,153		167,726

Net property, plant, and equipment	$	355,304	$	344,743

Commitments for construction and acquisition of property, plant, and equipment for the Tahiti pipeline lateral expansion are approximately $33.3 million at December 31, 2006.

Effective December 31, 2005, we adopted Financial Accounting Standards Board Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $327,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $151,000 increase in property, plant, and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $176,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. If the Interpretation had been in effect at the beginning of 2004, the impact to our income from continuing operations and net income would have been immaterial.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 4. Property, Plant, and Equipment (continued)

Our obligations relate to an offshore platform and our onshore processing and fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platform, remove the onshore facilities and related surface equipment and restore the surface of the property.

A rollforward of our asset retirement obligation for 2006 and 2005 is presented below.


	Years Ended December 31,
	2006		2005
	*(In thousands)*
Balance at January 1	$	1,121	$	702
Accretion expense		135		92
Estimate revisions		2,472		—
FIN No. 47 revisions		—		327

Balance at December 31	$	3,728	$	1,121

During the third quarter of 2007, we began our annual update of assumptions used in the calculation of our asset retirement obligations. We expect changes to these assumptions may significantly increase the recorded asset retirement obligation, primarily due to an increase in our cost estimates covered by recent retirements which indicated that actual retirement costs exceed our current estimate.

Note 5. Leasing Activities

We lease the land on which the Paradis fractionator plant and the Larose processing plant are located. The initial terms of the leases are 20 years with renewal options for an additional 30 years. We entered into a ten-year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP, as part of our Market Expansion project which began in June 2005 (see Note 7). The lease includes renewal options and options to increase capacity which would also increase rentals. The future minimum annual rentals under these non-cancelable leases as of December 31, 2006 are payable as follows:


	*(In thousands)*
2007	$	854
2008		858
2009		858
2010		858
2011		858
Thereafter		3,252

	$	7,538

Total rent expense for 2006, 2005 and 2004, including a cancelable platform space lease and month-to-month leases, was $1,383,261, $1,059,909 and $866,000, respectively.

Note 6. Financial Instruments and Concentrations of Credit Risk

Financial Instruments Fair Value

We used the following methods and assumptions to estimate the fair value of financial instruments:

Cash and cash equivalents. The carrying amounts reported in the consolidated balance sheets approximate fair value due to the short-term maturity of these instruments.

Restricted cash. The carrying amounts reported in the consolidated balance sheets approximate fair value as these instruments have interest rates approximating market.

Concentrations of Credit Risk

Our cash equivalents and restricted cash consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor’s or AA by Moody’s Investor’s Service.


	2006				2005
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	*(In thousands)*
Cash and cash equivalents	$	37,583	$	37,583	$	21,378	$	21,378
Restricted cash		28,773		28,773		44,559		44,559

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 6. Financial Instruments and Concentrations of Credit Risk (continued)

At December 31, 2006 and 2005, substantially all of our customer accounts receivable result from gas transmission services for and natural gas liquids sales to our two largest customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on receivables during 2006 and 2005.

Major Customers. Williams and Eni accounted for approximately $57.8 million (58%) and $10.9 million (11%), respectively, of our total revenues in 2004, and $70.8 million (58%) and $8.5 million (7%), respectively, of our total revenues in 2005. Williams and Texas Eastern Corporation accounted for approximately $149 million (75%) and $12.2 million (6%), respectively, of our total revenues in 2006.

Note 7. Rate and Regulatory Matters and Contingent Liabilities

Rate and Regulatory Matters. Annually, DGT files a request with the FERC for a lost-and-unaccounted-for gas percentage to be allocated to shippers for the upcoming fiscal year beginning July 1. On June 1, 2006, DGT filed to maintain a lost-and-unaccounted-for percentage of zero percent for the period July 1, 2006 to June 30, 2007 and to retain the 2005 net system gains of $1.2 million that are unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June 29, 2006 the filing was approved. On May 31, 2007, DGT filed to maintain a lost-and-unaccounted-for percentage of zero percent for the period July 1, 2007 to June 30, 2008 and to retain the 2006 net system gains of $1.8 million that are unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June 28, 2007 the filing was approved. The approval was subject to a 30 day protest period, which passed without protest. As of June 30, 2007 (unaudited), December 31, 2006 and 2005, DGT has deferred amounts of $5.4 million, $4.6 million and $6 million, respectively, included in current accrued liabilities in the accompanying Consolidated Balance Sheets representing amounts collected from customers pursuant to prior years’ lost and unaccounted for gas percentage and unrecognized net system gains.

On November 25, 2003, the FERC issued Order No. 2004 promulgating new standards of conduct applicable to natural gas pipelines. On August 10, 2004, the FERC granted DGT a partial exemption allowing the continuation of DGT’s current ownership structure and management subject to compliance with many of the other standards of conduct. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004 as applied to interstate natural gas pipelines and their affiliates. On January 9, 2007, the FERC issued an interim rule. The Interim Rule re-promulgates, on an interim basis, the standards of conduct that were not challenged before the Court. The Interim Rule applies to the relationship between interstate natural gas pipelines and their marketing and brokering affiliates, but not necessarily to their other affiliates, such as gatherers, processors or exploration and production companies. On March 21, 2007 the FERC issued an Order on Clarification and Rehearing of the Interim Rule. The FERC clarified that the interim standards of conduct only apply to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such natural gas transmission provider’s pipeline. Currently DGT’s marketing or brokering affiliates do no conduct transmission transactions on DGT. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking to propose permanent regulations regarding the standards of conduct. Comments were due April 4, 2007. The FERC may enact a final rule at any time. At this stage, it cannot be determined how a final rule may or may not affect Discovery.

On July 20, 2006, DGT and DPS filed applications for Certificates of Public Convenience and Necessity for DPS to provide to DGT the use of capacity on a DPS gathering line which would be subject to a Limited Jurisdiction Certificate. The capacity would be provided to DGT under a capacity lease and would allow DGT to effectuate transportation of gas received from Texas Eastern Transmission, LP for delivery to DPS’ Larose processing plant. DPS’ request for a Limited Jurisdiction Certificate would permit DGT’s use of DPS’ non-jurisdictional gathering line for DGT’s jurisdictional transportation without having DPS’ gathering and processing facilities and operations becoming subject to the full panoply of the Natural Gas Act. On November 26, 2006, the Commission issued an order granting the requested Certificates. The order was limited to interruptible service. On December 14, 2006, DGT and DPS filed a request for an amendment to the Certificates to permit DGT to offer firm service on the leased capacity. The Commission approved the request by order issued on March 23, 2007.

Pogo Producing Company. On January 16, 2006, DPS and DGT received notice of a claim by POGO Producing Company (“POGO”) relating to the results of a POGO audit performed first in April 2004 and then continued through August 2005. POGO claimed that DPS and DGT overcharged POGO and its working interest owners approximately $600,000 relating to condensate transportation and handling during 2000 — 2005. The underlying agreements limit audit claims to a two-year period from the date of the audit. DPS and DGT disputed the validity of the claim.

Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any noncompliance under the various environmental laws and regulations.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as of June 30, 2007 and for the six months ended June 30, 2007 and 2006 is unaudited

Note 7. Rate and Regulatory Matters and Contingent Liabilities (continued)

Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. Litigation, arbitration and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

Note 8. Subsequent Events (unaudited)

On January 10, 2007, we made a cash call to DCP Midstream for $2.4 million for the first quarter 2007 estimated expenditures on the Tahiti pipeline lateral expansion project.

On January 30, 2007, we made quarterly cash distributions totaling $9 million to our members.

On April 10, 2007, we made a cash call to DCP Midstream for $1.52 million for the second quarter 2007 estimated expenditures on the Tahiti pipeline lateral expansion project.

On April 30, 2007, we made quarterly cash distributions totaling $16 million to our members.

On June 22, 2007, we made cash distributions totaling $11.173 million to our members for insurance proceeds related to reimbursement of Hurricane Katrina repairs.

On June 28, 2007, Williams Partners Operating LLC, the operating subsidiary of Williams Partners L.P., entered into a Purchase and Sale Agreement with Williams Energy, L.L.C. and Williams Energy Services, pursuant to which the seller parties agreed to sell a 20% limited liability company interest in DPS to Williams Partners Operating LLC.

On July 1, 2007, DCP Midstream, LLC and affiliates contributed its entire 40% limited liability company interest in DPS to DCP Midstream Partners, LP.

On July 30, 2007, we made quarterly cash distributions totaling $9 million to our members.

Historical Combined Financial Statements of East Texas

Exhibit 99.2

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED FINANCIAL STATEMENTS

AS OF JUNE 30, 2007 (UNAUDITED), AND DECEMBER 31, 2006 AND 2005, AND

FOR THE PERIODS ENDED JUNE 30, 2007 AND 2006 (UNAUDITED), AND DECEMBER 31, 2006, 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

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED BALANCE SHEETS

($ in millions)


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

Total current assets		26.8		31.1		31.3
Property, plant and equipment, net		232.5		227.5		227.2
Other non-current assets		—		—		0.1

Total assets	$	259.3	$	258.6	$	258.6


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

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

Total liabilities		57.0		55.7		64.6
Commitments and contingent liabilities
Net parent equity		202.3		202.9		194.0

Total liabilities and net parent equity	$	259.3	$	258.6	$	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,				Year Ended December 31,
	2007		2006		2006			2005			2004
	(unaudited)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	28.2	$	113.9	$	177.7		$	164.7		$	64.7
Sales of natural gas, NGLs and condensate to affiliates		166.2		144.9		286.6			365.6			308.1
Transportation and processing services		9.9		9.2		21.9			17.1			13.4
Transportation and processing services to affiliates		0.1		0.2		0.3			0.3			0.3
Gains (losses) from non-trading derivative activity — affiliates		0.1		0.3		(1.1	)		(1.7	)		(0.1	)

Total operating revenues		204.5		268.5		485.4			546.0			386.4

Operating costs and expenses:
Purchases of natural gas and NGLs		155.9		209.7		376.0			418.8			306.7
Purchases of natural gas and NGLs from affiliates		1.1		5.3		9.3			25.3			3.6
Operating and maintenance expense		15.7		11.1		25.2			20.2			16.3
Depreciation expense		7.9		7.1		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		11.3			9.8			8.1

Total operating costs and expenses		187.8		238.3		436.6			488.2			349.4

Operating income		16.7		30.2		48.8			57.8			37.0
Income tax expense		0.2		1.8		1.8			—			—

Net income	$	16.5	$	28.4	$	47.0		$	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		47.0

Balance, December 31, 2006		202.9
Net change in parent advances (unaudited)		(17.1	)
Net income (unaudited)		16.5

Balance, June 30, 2007 (unaudited)	$	202.3

See accompanying notes to combined financial statements.

THE EAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CASH FLOWS

($ in millions)


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
	(unaudited)
OPERATING ACTIVITIES:
Net income	$	16.5		$	28.4		$	47.0		$	57.8		$	37.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		7.9			7.1			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			0.3			(16.9	)		2.0
Accounts payable		1.5			(29.1	)		(12.6	)		33.1			1.8
Other current assets and liabilities		1.3			(0.3	)		(1.0	)		1.8			—
Other non-current assets and liabilities		—			(0.2	)		(0.2	)		(0.1	)		(0.2	)

Net cash provided by operating activities		32.3			20.4			50.0			89.8			55.0


INVESTING ACTIVITIES:
Capital expenditures		(15.2	)		(7.7	)		(12.0	)		(6.1	)		(1.5	)
Proceeds from sales of assets		—			—			0.1			0.1			—

Net cash used in investing activities		(15.2	)		(7.7	)		(11.9	)		(6.0	)		(1.5	)


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

Net cash used in financing activities		(17.1	)		(12.7	)		(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, the combined statement of changes in net parent equity for the six months ended June 30, 2007, and the combined balance sheet as of June 30, 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, and December 31, 2006 and 2005, were imbalances totaling $0.2 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, and December 31, 2006 and 2005, were imbalances totaling $2.2 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, and December 31, 2006 and 2005, included in the combined balance sheets as other current liabilities, were $0.2 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.

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, and the six months ended June 30, 2007, was a reduction of sales and purchases of approximately $44.3 million and $69.2 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), 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,				Year Ended December 31,
	2007		2006		2006		2005		2004
	(unaudited)
DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate	$	162.9	$	135.0	$	276.3	$	355.2	$	289.2
General and administrative expense	$	6.0	$	4.9	$	11.3	$	9.8	$	8.1
Duke Energy Corporation:
Sales of natural gas, NGLs and condensate	$	—	$	6.6	$	6.6	$	6.7	$	12.2
Purchases of natural gas and NGLs	$	—	$	0.1	$	0.1	$	3.8	$	1.6
ConocoPhillips:
Sales of natural gas, NGLs and condensate	$	3.3	$	3.3	$	3.7	$	3.7	$	6.7
Transportation and processing services	$	0.1	$	0.2	$	0.3	$	0.3	$	0.3
Purchases of natural gas and NGLs	$	1.1	$	5.2	$	9.2	$	21.5	$	2.0

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


	June 30, 2007		December 31,
	June 30, 2007		2006		2005
	(unaudited)
Duke Energy Corporation:
Accounts receivable	$	—	$	—	$	2.4
ConocoPhillips:
Accounts receivable	$	1.1	$	0.1	$	0.1
Accounts payable	$	0.1	$	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			December 31,
	Depreciable Life	June 30, 2007			2006			2005
		(unaudited)
Gathering systems	15 — 30 Years	$	72.7		$	70.0		$	59.6
Processing plants	25 — 30 Years		218.5			218.4			218.1
Transportation	25 — 30 Years		34.2			34.3			34.2
General plant	3 — 5 Years		7.6			7.2			6.8
Construction work in progress			15.0			5.7			2.1

			348.0			335.6			320.8
Accumulated depreciation			(115.5	)		(108.1	)		(93.6	)

Property, plant and equipment, net		$	232.5		$	227.5		$	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, 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), 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, and December 31, 2006 and 2005, included in the combined balance sheets as other long-term liabilities, was $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. Subsequent Event

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

Historical Consolidated Financial Statements of Momentum

Exhibit 99.3

Momentum Energy Group, Inc. and Subsidiaries

Consolidated Financial Statements as of June 30, 2007, December 31, 2006 and 2005, and for the Six Month Periods Ended June 30, 2007 and 2006 (Unaudited), the Years Ended December 31, 2006 and 2005, and for the Period August 24, 2004 (Date of Inception) Through December 31, 2004, and Independent Auditors’ Report


								Deloitte & Touche LLP Suite 2300 333 Clay Street Houston, TX 77002-4196 USA

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of

Momentum Energy Group, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Momentum Energy Group, Inc. and subsidiaries (the “Company”) as of June 30, 2007, December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the six month period ended June 30, 2007, the years ended December 31,2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Momentum Energy Group, Inc. and subsidiaries at June 30, 2007, December 31, 2006 and 2005, and the results of their operations and their cash flows for the six month period ended June 30, 2007, the years ended December 31, 2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

LOGO

August 22, 2007

Member of

Deloitte Touche Tohmatsu

MOMENTUM ENERGY GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF JUNE 30, 2007, DECEMBER 31, 2006 AND 2005

(In thousands)


	June 30, 2007			December 31, 2006			December 31 2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	20,569		$	39,441		$	26,299
Accounts receivable — net		19,310			17,641			471
Accounts receivable — partners and affiliates		44			1,023			5,216
Prepayments and other		1,526			851			710
Risk management assets		1,000			2,592			—

Total current assets		42,449			61,548			32,696
PROPERTY, PLANT AND EQUIPMENT — Net		249,535			225,023			48,013
INTANGIBLE ASSETS — Net		21,011			19,277			44
RISK MANAGEMENT ASSETS		—			29			—
OTHER ASSETS		770			662			—

TOTAL	$	313,765		$	306,539		$	80,753

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	28,453		$	30,956		$	6,996
Other accrued liabilities		3,548			1,747			262
Deferred revenue		1,679			11,595			—
Customer deposits		2,974			—			—
Accounts payable-partners and affiliates		99			—			—
Current maturities of long-term debt		660			475			15
Notes payable		—			—			15,000

Total current liabilities		37,413			44,773			22,273
LONG-TERM DEBT		22,101			22,674			58
OTHER LONG-TERM LIABILITIES		3,391			1,642			47
MINORITY INTEREST		22,244			18,471			—
STOCKHOLDERS’ EQUITY:
Common Stock, $0.01 par value — authorized, 2,500,000 shares; issued, 1,669,358 at June 30, 2007 and December 31, 2006, and 750,000 at December 31, 2005		17			17			8
Additional paid-in capital		227,954			227,551			60,431
Notes receivable from stockholders		(13,181	)		(13,301	)		—
Retained earnings (deficit)		13,826			4,712			(2,064	)

Total stockholders’ equity		228,616			218,979			58,375

TOTAL	$	313,765		$	306,539		$	80,753

See notes to consolidated financial statements.

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MOMENTUM ENERGY GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE SIX MONTH PERIODS ENDED JUNE 30, 2007 AND 2006 (UNAUDITED),

THE YEARS ENDED DECEMBER 31, 2006 AND 2005, AND FOR THE PERIOD

AUGUST 24, 2004 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2004

(In thousands)


	Six Months Ended June 30, 2007			Six Months Ended June 30, 2006 (Unaudited)			Year Ended December 31, 2006			Year Ended December 31, 2005			For the Period August 24, 2004 (Date of Inception) through December 31, 2004
REVENUES:
Natural gas and liquids sales	$	58,074		$	9,713		$	52,663		$	1,132		$	—
Gathering and processing fees		10,494			1,176			5,496			288
Construction revenues		1,557			680			2,006			264			—
Other revenues		10,381			112			1,600			—			—
(Loss) gain on risk management instruments		(468	)		(1,492	)		3,763			—			—

Total revenues		80,038			10,189			65,528			1,684			—

OPERATING COSTS AND EXPENSES:
Cost of natural gas and liquids		50,120			8,469			45,637			809			—
Operations and maintenance		7,490			1,885			7,097			1,108			—
General and administrative expenses		4,966			2,186			6,297			1,082			384
Depreciation and amortization		6,792			1,055			5,469			486			2
Loss (gain) on sale of assets		29			—			(4,666	)		—			—

Total operating costs and expenses		69,397			13,595			59,834			3,485			386

OPERATING INCOME (LOSS)		10,641			(3,406	)		5,694			(1,801	)		(386	)
OTHER INCOME AND EXPENSE:
Interest expense		(14	)		—			—			(4	)		—
Interest income		546			382			970			127			—

Total other income		532			382			970			123
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST		11,173			(3,024	)		6,664			(1,678	)		(386	)
INCOME TAX EXPENSE		1,454			—			—			—			—

INCOME (LOSS) BEFORE MINORITY INTEREST		9,719			(3,024	)		6,664			(1,678	)		(386	)
MINORITY INTEREST IN (EARNINGS) LOSS OF SUBSIDIARY		(605	)		—			112			—			—

NET INCOME (LOSS)	$	9,114		$	(3.024	)	$	6,776		$	(1,678	)	$	(386	)

See notes to consolidated financial statements.

-3-

MOMENTUM ENERGY GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2007, THE YEARS ENDED DECEMBER 31, 2006 AND 2005,

AND FOR THE PERIOD AUGUST 24, 2004 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2004

(In thousands except share amounts)


	Common Stock			Additional Paid-in Capital			Notes Receivable From Stockholders			Retained Earnings (Deficit)			Total
	Shares	Amount		Additional Paid-in Capital			Notes Receivable From Stockholders			Retained Earnings (Deficit)			Total
BALANCE — August 24, 2004
(date of inception)	—	$	—	$	—		$	—		$	—		$	—
Net loss	—		—		—			—			(386	)		(386	)

BALANCE — December 31, 2004	—		—		—			—			(386	)		(386	)
Common stock issued	750,000		8		74,992			—			—			75,000
Deemed distributions	—		—		(14,561	)		—			—			(14,561	)
Net loss	—		—		—			—			(1,678	)		(1,678	)

BALANCE — December 31, 2005	750,000		8		60,431			—			(2,064	)		58,375
Common stock issued	919,358		9		166,772			—			—			166,781
Management share notes receivable	—		—		—			(13,680	)		—			(13,680	)
Payments on notes receivable	—		—		—			379			—			379
Equity-based compensation	—		—		348			—			—			348
Net income	—		—		—			—			6,776			6,776

BALANCE — December 31, 2006	1,669,358		17		227,551			(13,301	)		4,712			218,979
Payments on notes receivable	—		—		—			120			—			120
Equity-based compensation	—		—		403			—			—			403
Net income	—		—		—			—			9,114			9,114

BALANCE — June 30, 2007	1,669,358	$	17	$	227,954		$	(13,181	)	$	13,826		$	228,616

See notes to consolidated financial statements.

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MOMENTUM ENERGY GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE SIX MONTH PERIODS ENDED JUNE 30, 2007 AND 2006 (UNAUDITED),

THE YEARS ENDED DECEMBER 31, 2006 AND 2005, AND FOR THE PERIOD

AUGUST 24, 2004 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2004

(In thousands)


	Six Months Ended June 30, 2007			Six Months Ended June 30, 2006 (Unaudited)			Year Ended December 31, 2006			Year Ended December 31, 2005			For the Period August 24, 2004 (Date of Inception) through December 31, 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,114		$	(3,024	)	$	6,776		$	(1,678	)	$	(386	)
Changes to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		6,792			1,055			5,469			486			2
Loss (gain) on sale of assets		29			—			(4,666	)		—			—
Equity-based compensation		403			101			348			—			—
Minority interest in net earnings (loss) of subsidiary		605			—			(112	)		—			—
Risk management activities		1,621			1,492			(2,621	)		—			—
Accounts receivable		(3,914	)		(1,644	)		(14,173	)		(942	)		—
Prepayments and other		(55	)		(233	)		(217	)		(156	)		—
Deferred revenue		(9,933	)		60			11,588			—			—
Customer deposits		2,974
Deferred taxes		1,419
Accounts payable and other accruals		(209	)		1,357			14,748			1,464			43

Net cash provided (used) by operating activities		8,846			(836	)		17,140			(826	)		(341	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions		—			(42,737	)		(42,737	)		(32,500	)		—
Purchases of property, plant, and equipment		(28,575	)		(42,852	)		(131,539	)		(29,403	)		(12	)
Purchases of intangibles		(2,683	)		(9,908	)		(10,353	)		(45	)
Other asset purchases		(171	)		(513	)		(1,181	)		(532	)		(36	)
Cash received from sale of plant		—			—			6,800			—			—

Net cash used by investing activities		(31,429	)		(96,010	)		(179,010	)		(62,480	)		(48	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		—			25,775			49,000			47,553			389
Payments on borrowings		(447	)		(5,093	)		(44,283	)		(32,948	)		—
Loan fees		(223	)		(775	)		(775	)		—			—
Net proceeds from equity offerings		—			52,600			153,101			75,000			—
Proceeds from payment on note receivable from stockholder		120			—			379			—			—
Proceeds from minority interest		4,261			—			17,590			—			—

Net cash provided by financing activities		3,711			72,507			175,012			89,605			389

NET CASH AND CASH EQUIVALENTS (DECREASE) INCREASE FOR PERIOD		(18,872	)		(24,339	)		13,142			26,299			—
CASH AND CASH EQUIVALENTS — Beginning of period		39,441			26,299			26,299			—			—

CASH AND CASH EQUIVALENTS — End of period	$	20,569		$	1,960		$	39,441		$	26,299		$	—

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING AND INVESTING ACTIVITIES:
Pipeline asset received in exchange for sale of plant	$	—		$	—		$	1,659		$	—		$	—

Capital leases to acquire assets	$	531		$	2,702		$	2,913		$	80		$	—

Stock issued for notes receivable	$	—		$	10,024		$	13,680		$	—		$	—

Capital expenditures in accounts payable	$	15,576		$	27,706		$	13,857		$	5,756		$	10

See notes to consolidated financial statements.

- 5 -

MOMENTUM ENERGY GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2007, DECEMBER 31, 2006 AND 2005

AND FOR THE SIX MONTH PERIODS ENDED JUNE 30, 2007 AND 2006 (UNAUDITED),

THE YEARS ENDED DECEMBER 31, 2006 AND 2005, AND

FOR THE PERIOD AUGUST 24, 2004 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2004

1.	ORGANIZATION

General — Momentum Energy Group, Inc. ( “MEI”), a Delaware company formed in November 2005, is engaged, through its subsidiaries, in the gathering, treating and processing of natural gas and natural gas liquids (“NGL”). MEI is a portfolio company of private equity firms: Yorktown Energy Partners LLC (“Yorktown”), Banc of America Capital Investors SBIC, L.P. and Lehman Brothers MLP Partners, L.P. MEI’s wholly owned subsidiary, Momentum Energy Group, LLC (“MEG”) was formed on August 24, 2004 and previously was a wholly owned subsidiary of Peak Energy Resources, Inc. (“Peak”), also a Yorktown portfolio company. MEI was formed to acquire MEG from Peak (see Note 4). The accompanying financial statements include the results of operations of MEI from November 2005 and the results of operations of MEG for the periods prior to November 2005. The reorganization of these entities was accounted for as a reorganization of entities under common control.

MEI, through our subsidiaries (collectively the “Company”), provides midstream energy services, including gathering, treating and processing of natural gas and NGL in three geographic regions: the Fort Worth Basin of Texas, the Piceance Basin of Colorado and the Powder River Basin of Wyoming. In addition to MEG, MEI operates through three principal business entities: MEG Texas Gas Gathering, LP (“MEG Texas”), MEG Colorado Gas Gathering, LLC (“MEG Colorado”) and MEG Wyoming Gas Service, LLC (“MEG Wyoming”). The following is a brief description of the Company’s current operations.

MEG Texas was formed in January 2005 and owns and operates a gas gathering system and associated processing plant that gathers and processes customer’s gas produced from the Barnett Shale formation of the Fort Worth Basin. The gathering system utilizes newly installed medium pressure gathering lines in Hood, Erath, Parker and Somervell counties. MEG Texas also owns and operates an NGL products pipeline.

MEG Colorado was formed in February 2006 to construct a gathering system and treating and processing plant in the Piceance Basin. MEG Colorado contributed its assets to a newly formed subsidiary, Collbran Valley Gas Gathering, LLC (“CVG”) in September 2006 concurrent with a cash contribution to CVG from Laramie Energy, LLC (“Laramie”) and Delta Petroleum Corporation (“Delta”). The member interests in CVG of MEG Colorado, Laramie and Delta are 70%, 25% and 5%, respectively. The processing plant became operational in November 2006. On May 31, 2007, Plains Exploration and Production Company acquired the Piceance Basin midstream properties of Laramie and became the 25% partner at CVG.

MEG Wyoming was formed in April 2006 to purchase a gathering system from KM Upstream, LLC (“Kinder Morgan”). The gathering system consists of low, medium, and high pressure gathering lines and compressor stations. Natural gas is delivered to Kinder Morgan’s Douglas plant under a processing agreement whereby Kinder Morgan processes, treats, and markets the natural gas and NGL.

- 6 -

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principals of Consolidation — The accompanying consolidated financial statements and related notes include our assets, liabilities, and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in the consolidated financial statements.

The portion of the income (loss) and net assets applicable to the Company’s noncontrolling interest in the majority-owned operations of Collbran Valley Gas Gathering, LLC is reflected as minority interest.

Interim Condensed Disclosures — The information for the six month period ended June 30, 2006 is unaudited but in the opinion of management, reflects all adjustments which are normal, recurring and necessary for a fair presentation of financial position and results of operations for the interim periods. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission.

Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets, liabilities, revenues, and expense and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although our management believes the estimates are appropriate, actual results can differ from those estimates.

Cash and Cash Equivalents — Cash and cash equivalents are defined as time deposits and highly liquid investments with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short terms to maturity of these investments.

Accounts Receivable and Allowance for Doubtful Accounts — Credit is extended to our customers in our normal course of business. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of reserves, judgments are made regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, and rights of offset. There are circumstances in which we require a customer to prepay or provide us with a letter of credit to limit credit risk. For the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004, we did not record any allowance for doubtful accounts.

Imbalances — In the course of shipping natural gas and NGL, which are comprised of Ethane, Propane, Butanes, and Pentanes, for others, we may receive for redelivery different quantities of natural gas or NGL than the quantities actually redelivered. These transactions result in imbalance receivables or payables that are recovered or repaid through receipt or delivery of natural gas and NGL in future periods, if not subject to cash-out provisions and are marked-to-market using current market prices in effect for the reporting period. Imbalance receivables are included in our current assets and imbalance payables are included in current liabilities. As of June 30, 2007 and December 31, 2006, our imbalance receivable was $54,142 and $8,599, respectively. We did not have an imbalance receivable as December 31, 2005. Our imbalance payables as of June 30, 2007 and December 31, 2006 and 2005, were $372,130, $203,052 and $25,195, respectively.

- 7 -

Product Inventories — In the normal course of business, we have storage tanks that hold NGL until they can be sold and/or trucked to market. All product inventories are valued at the lower of average cost or market. As of June 30, 2007 and December 31, 2006 and 2005, our product inventories were $115,862, $251,542, and $548, respectively. Product inventories are included in prepayments and other on the consolidated balance sheet.

Property, Plant, and Equipment — The Company’s property, plant, and equipment consists of gas gathering systems, gas processing and treating facilities, and other related facilities, which are carried at cost less accumulated depreciation. Expenditures related to property, plant and equipment that have a useful life greater than one year are capitalized. All repairs and maintenance items are charged against income when incurred and renewals and betterments, which extend the useful life greater than one year or expand the capacity of the asset, are capitalized. All land costs are capitalized.

Depreciation is calculated on the straight-line method based on the estimated useful lives of our assets as follows:


Pipelines and pipeline associated		16-25 years
Gas processing plants and equipment		16-40 years
Other assets		2-10 years

Construction in Progress — During construction, all direct costs, such as labor, materials, freight, installation and other costs, such as direct overhead are capitalized within construction in progress (CIP). Upon completion of the project or at the completion of a major phase, the project construction costs are placed in service and depreciated accordingly.

Capitalized Interest —We capitalize interest on projects during extended construction time periods. Such interest is allocated to CIP under the project and allocated to property, plant and equipment when complete and depreciated with the asset. For the six month periods ended June 30, 2007 and 2006, the years ended December 31,2006 and 2005, the Company capitalized $887,273, $741,794 (unaudited), $2,227,822 and $98,585, respectively, of interest related to major projects. No interest was capitalized during 2004.

Derivative Instruments — The Company enters into certain financial contracts to manage its exposure to movement in commodity prices. The Company applies the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, to its derivative instruments. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. Normal purchases and normal sales are contracts which provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Company’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. The Company uses swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices. These financial instruments are recognized on the consolidated balance sheet at the instrument’s fair value with changes in fair value reflected in the statement of operations, as the Company has not designated any of these derivative instruments as hedges.

Intangible Assets — Intangible assets consist of rights-of-way (“ROW”) and easements, customer contracts and customer relationships. The Company’s customer contracts and relationships are related to the assets purchased from Kinder Morgan in April of 2006. The value of the contracts was derived by management with the assistance of a third-party valuation firm. All

- 8 -

ROW intangible assets are amortized on a straight-line basis over the estimated useful life. The customer contracts and customer relationship intangible assets are amortized on an accelerated basis which reflects projected declines in production volumes. Weighted average estimated lives of ROW intangibles and customer contracts/relationships at June 30, 2007 are 20.4 years and 11.6 years, respectively. The amortization expense associated with intangibles for the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005 and for the period August 24, 2004 (date of inception) through December 31, 2004, were $827,611, $95,861 (unaudited), $742,462, $1,888, and $0, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2007 (remainder) — $767,493; 2008 — $1.6 million; 2009 — $1.5 million; 2010 — $1.4 million; 2011 — $1.3 million and 2012 — $1.2 million. Intangible assets consisted of the following (in thousands):


	June 30, 2007			December 31, 2006			December 31, 2005
Rights-of-way and easements — at cost	$	17,697		$	15,139		$	46
Less accumulated amortization		(675	)		(262	)		(2	)
Customer contracts and relationships		4,882			4,882			—
Less accumulated amortization		(893	)		(482	)		—

Net intangible assets	$	21,011		$	19,277		$	44

Impairment of Assets — The Company reviews and evaluates its long-lived assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. An impairment loss is measured as the amount by which asset carrying value exceeds fair value. The Company recorded no impairment for the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004.

Environmental — The Company is subject to various federal, state, and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with Statement of Position 96-1, Environmental Remediation Liabilities. Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which 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-up are probable and the costs can be reasonably estimated. In the asset purchase agreement for the Wyoming assets, Kinder Morgan has indemnified the Company with respect to environmental matters for a period of two years and an amount of $11 million. At June 30, 2007, December 31, 2006 and 2005, the Company had no environmental matters requiring accruals.

Deferred Revenue — The Company records deferred revenue for payments received from customers in advance of recognizing revenue.

- 9 -

Revenue Recognition — The Company and its subsidiaries recognize natural gas and NGL revenues in the calendar month of production according to customer contracts. Revenues are derived from the following types of arrangements:

Fee-Based Arrangements — Under the terms of fee-based contracts, the Company receives a set fee for gathering, treating and processing natural gas. These revenues correspond with volumes and are not directly dependent on commodity prices.

Percent of Proceeds — Under the terms of percent of proceeds contracts, the Company receives a negotiated percentage of the natural gas and NGL, which are sold through a marketing company at market prices. We recognize 100% of the proceeds for the gas and the producers negotiated percentage of natural gas, NGL and, in some cases, condensate during the month of production.

Wellhead Purchase — Under the terms of a wellhead purchase contract, we pay a negotiated price for natural gas at the wellhead. We then keep 100% of the proceeds for the natural gas, the NGL and the condensate.

Construction Revenues — In the normal course of business, the Company generates revenues related to the construction of pipelines and central delivery points (CDPs) to connect producers’ gas to our pipelines and revenues related to the installation and operation of lift gas services for our producers. The pipelines, CDPs, and lift gas services enable producer gas to be gathered, processed, and ultimately sold in the market place. Certain producer contracts allow the Company to charge an additional overhead percentage of the total costs as management fees. The Company pays the cost to build these facilities and re-bills those costs to the producer. The Company owns and operates the facilities after completion.

Other Revenues — The Company is periodically contracted to relocate certain portions of its gathering pipeline in Wyoming to accommodate the expansion plans of coal mines operating in the area. These coal mines compensate the Company to relocate our pipeline. The Company retains ownership of the pipeline. Projects of this nature are not considered normal operations for the Company. For the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005 and for the period August 24, 2004 (date of inception) through December 31, 2004 other revenues includes $9,953,707, $0 (unaudited), $785,248, $0, and $0, respectively, of pipeline relocation revenues.

Income Taxes — The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. As of June 30, 2007 and December 31, 2006 we have an estimated net operating loss carryforward of approximately $23.4 million and $12.8 million which begins to expire in 2026 and 2025, respectively. For the six month period ending June 30, 2007, the Company recorded a deferred federal tax provision of $1.3 million. No federal income tax expense was recognized for the six month periods ended June 30, 2006, the years ended December 31, 2006 and 2005, and for the period August 24, 2004 (date of inception) through December 31, 2004.

Net deferred long-term tax liabilities at June 30, 2007 relate to the net operating loss carryforward and book tax basis differences resulting primarily from property, plant and equipment. Net deferred long-term tax liabilities as of June 30, 2007 of $1,417,000 are recorded in other long-term liabilities on the consolidated balance sheet. Net deferred current tax assets relate primarily to income recognition and derivatives. Net deferred current tax assets of $96,000 are recorded in prepayments and other on the consolidated balance sheet. Net deferred tax assets relate to the net operating loss carryforward and book tax basis differences

- 10 -

resulting primarily from property, plant and equipment, derivatives, and income recognition and have been fully reserved as of December 31, 2006 and 2005. As of December 31, 2006 and 2005, the Company had valuation allowances of $8.3 million and $15.4 million, respectively.

In May 2006, the state of Texas enacted a margin tax which will become effective in 2008. This margin tax will require the Company to determine a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes, less the cost of the products sold for federal income tax purposes, in the State of Texas. Under the provisions of SFAS No. 109, Accounting for Income Taxes, the Company is required to record the effects on deferred taxes for a change in tax rates or tax law in the period which includes the enactment date. This impact of this tax law change was not material for the year ended December 31, 2006. During the six month period ended June 30, 2007, the Company recorded $34,956 of current and $97,913 of deferred state income tax expense.

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes, by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be take on a tax return. If a tax position is “more likely than not” to be sustained upon examination, the entity would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The Company adopted the provisions of FIN 48 effective as of the beginning of the Company’s 2007 fiscal year. The adoption of FIN 48 did not have a material effect on our consolidated financial position or results of operations.

Stock-Based Compensation — The Company adopted SFAS No. 123(R), Share-Based Payment, as revised, as of first quarter 2006 when options were first issued. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

3.	NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements — In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No 133. The standard is effective for reporting periods beginning after November 15, 2007. We are evaluating the impact of SFAS No 157.

Fair Value Option for Financial Assets and Financial Liabilities — In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. The Company has not yet determined whether we will choose to measure items subject to SFAS No. 159 at fair value.

4.	ACQUISITION

Momentum Energy Group, LLC — Peak funded the initial startup of a gas gathering and processing business through its wholly owned subsidiary, MEG. The intention was for MEG to be separated into a separate Yorktown funded entity at a later date. In November 2005, MEI was formed with initial capitalization of $75 million from Yorktown. Upon formation, MEI acquired MEG from Peak for $47.5 million of cash and notes. The acquisition included all of the natural gas gathering and processing assets, CIP, and negotiated contracts for MEG and its wholly owned subsidiaries.

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The purchase price was determined by management with the assistance of an independent appraisal of MEG and its subsidiaries by an investment banking firm specializing in the energy industry (in thousands).


Purchase price:
Cash	$	32,500
Notes payable		15,000

Total purchase price		47,500

Allocation of purchase price:
Current assets		3,340
Gas gathering and processing assets		618
Vehicles		292
Other assets		473
Construction in progress		33,664
Long-lived customer contracts		94
Accumulated depreciation		(65	)
Current year and retained loss		1,697
Current liabilities		(7,174	)

Total allocation of purchase price		32,939

Deemed distribution (excess over book)	$	14,561

As MEI and Peak had similar ownership, this transaction resulted in the transfer of assets to MEI at the carrying value of MEG’s books. This resulted in a deemed distribution for the excess purchase price over the carrying value of $14.6 million.

Douglas Gathering System — Effective April 1, 2006, the Company, through MEG Wyoming, acquired the Douglas Gathering System located in Wyoming from KM Upstream, LLC for $42.0 million in cash. Included in the asset purchase were pipelines, compressor stations, an idle NGL fractionation plant, and a terminal facility.

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The preliminary purchase price allocation was determined by management with the assistance of a third-party valuation firm and allocated as of December 31, 2006 as presented below (in thousands).


Purchase price:
Cash	$	42,037
Direct acquisition costs		700

Total purchase price	$	42,737

Allocation of purchase price:
Gas gathering and processing assets	$	34,364
Vehicles		179
Line pack		96
Rights-of-way		4,896
Customer contracts		904
Customer relationships		3,978
Current assets		302
Current liabilities		(140	)
Asset retirement obligations		(1,842	)

Total allocation of purchase price	$	42,737

5.	PROPERTY, PLANT, EQUIPMENT AND ASSET RETIREMENT OBLIGATION

Property, plant and equipment at June 30, 2007, December 31, 2006 and 2005, consisted of the following (in thousands);


	June 30, 2007			December 31, 2006			December 31, 2005
Property, plant and equipment — at cost:
Pipelines and equipment	$	154,237		$	132,002		$	18,520
Gas processing plants and equipment		69,368			63,874			7,788
Construction in process		31,138			30,108			20,807
Vehicles		1,333			1,151			351
Furniture and computer equipment		1,215			1,085			235
Buildings and leasehold improvements		1,098			1,164			333
Land		454			454			449
Line pack		676			217			15

Total property, plant and equipment		259,519			230,055			48,498

Less accumulated depreciation		(9,984	)		(5,032	)		(485	)

Property, plant and equipment — net	$	249,535		$	225,023		$	48,013

Depreciation expense for the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005 and for the period August 24, 2004 (date of inception) through December 31, 2004, was $5,731,075, $931,620 (unaudited), $4,550,376, $484,354, and $1,561, respectively.

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Asset Retirement Obligations — In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires the Company to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the periods in which the obligation is incurred and can be reasonably estimated. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset is recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, a company either settles the obligation for its recorded amount or incurs a gain or loss on settlement.

In March 2005 the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. FIN 47 clarifies that the terms, conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the company. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, a company is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. In these circumstances, the Company is required to determine if there is a range of potential settlement dates and the probabilities associated with this range based on a variety of factors including industry practice, management’s intent, and the asset’s economic life. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

The Company’s asset retirement obligations relate to: (i) rights-of-way and easements over property we do not own and (ii) regulatory requirements where a legal or contractual obligation exists upon abandonment of the related facility. The Company has recorded a long-term liability at June 30, 2007, December 31, 2006 and 2005, of $1,571,006, $1,642,219, and $46,542, respectively.

A rollforward of our liability for asset retirement obligations is as follows (in thousands):


Asset retirement obligations — January 1, 2005	$	—
Additions		47
Accretion expense		—

Asset retirement obligations — December 31, 2005		47
Additions		1,531
Accretion expense		64

Asset retirement obligations — December 31, 2006		1,642
Additions		142
Revision in estimates		—
Liabilities settled		(273	)
Accretion expense		60

Asset retirement obligations — June 30, 2007	$	1,571

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6.	LONG-TERM DEBT

Credit Agreement — On May 31, 2006, we entered into a $50 million credit agreement (the “Credit Agreement”) with the Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders. Our Credit Agreement included a $5 million sub-limit for the issuance of standby letters of credit. Initial availability under the facility was $32 million. In July 2006, the Credit Agreement was amended to, among other things, increase availability to $50 million. In September 2006, a second amendment allowed for the transactions surrounding the formation of CVG and the resulting member contributions by Laramie and Delta. In November 2006, a third amendment to the credit agreement provided for, among other things, the modification of loan covenant requirements.

In March 2007, the Company entered into a $75 million Amended and Restated Credit Agreement (“Amended Credit Agreement”), which provided for, among other things, a reduction in interest rates, an increase in the standby letter of credit sub-limit to $15 million, and a modification of the debt covenants for 2007. The Amended Credit Agreement has a maturity date of May 31, 2010.

The Credit Agreement and amendments in effect at June 30, 2007 contained various covenants that limit us and our operating subsidiaries’ ability to: (i) grant liens; (ii) be liable for other indebtedness; (iii) engage in a merger, consolidation or dissolution; (iv) enter into transactions with affiliates; (v) sell or otherwise dispose of our assets, businesses or operations; and (vi) make acquisitions and investments.

The Credit Agreement and amendments in effect at June 30, 2007, also contain covenants which, among other things, require us to maintain certain ratios or conditions as follows:

•

Earnings before interest, taxes, depreciation, and amortization (EBITDA) to interest expense (as defined) of not less than 2.50:1 commencing, March 31, 2007.

•

Total consolidated funded debt to EBITDA (as defined) of not more than 4.00:1 commencing December 31, 2007

•

Total consolidated funded debt to consolidated capitalization (as defined) to be less than 0.35:1 commencing March 31, 2007

The obligations under the Credit Agreement are secured by first priority liens on all of our assets and all of the assets, other than the Collbran assets, of our operating subsidiaries.

At our election, interest under the Credit Agreement is determined by reference to either the British Bankers Association LIBOR rate (LIBOR), plus an applicable margin of 1.50% to 2.50% per annum, or the Applicable Base Rate (ABR) defined as the higher of the federal funds rate or Prime rate in effect plus an applicable margin of 0.25% to 1.25%. Interest is payable quarterly for ABR loans and upon maturity on LIBOR loans, except that if a LIBOR loan has a term of six months, interest will be paid at the end of each three month period. The Amended Credit Agreement provides for an applicable margin of 1.50% to 2.25% on LIBOR borrowings and 0.25% to 1.00% on ABR borrowings.

If an event of default exists under the Credit Agreement, the Administrative Agent may terminate the revolving loan commitments and/or declare the loans then outstanding to be due and payable in whole or in part together with the accrued interest thereon and all fees. Each of the following would be an event of default:

•

Failure to pay any principal when due or any interest, fees or other amount within certain grace periods

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•

Failure of any representations in any report, certificate, financial statement or other document to be materially correct

•

Failure to observe or perform any covenant, condition, or agreement

•

The occurrence of any event or condition that causes material indebtedness to become due prior to its scheduled maturity or enables or permits the holders of such debt to pursue payment prior to its scheduled maturity

•

A change in control as defined in the Credit Agreement

•

Other customary defaults, including bankruptcy or insolvency events involving us or our subsidiaries

On May 31, 2006, we borrowed $25.7 million as an initial draw on the Credit Agreement to fund the acquisition of the MEG Wyoming assets. In addition, we borrowed an additional $24.0 million and repaid $29.7 million during the period May 31, 2006 to December 31, 2006. The balance outstanding at both December 31, 2006 and June 30, 2007 was $20.0 million.

Substantially all borrowings were on a LIBOR basis and interest rates ranged from 6.875% to 7.6875%. Total interest paid for the six month periods ended June 30, 2007 and 2006, and the year ended December 31, 2006, was $713,403, $163,689 (unaudited), and $1.4 million dollars, respectively.

Other long-term debt is comprised of capital leases payable for equipment and vehicles of $2,101,041. Total equipment and vehicles purchased under capital lease commitments as of June 30, 2007, December 31, 2006 and December 31, 2005 was $3,022,411, $2,993,307, and $139,646, respectively. All capital leases are eligible for early payoff. Amortization of capital assets recorded under capital leases is included in depreciation.

Future lease payments as of June 30, 2007, are as follows (in thousands):


2007 (remainder)	$	583
2008		584
2009		584
2010		571
2011		515
Thereafter		535

	$	3,372

7.	STOCKHOLDERS’ EQUITY

As of June 30, 2007 and December 31, 2006, the Company had 1,669,358 common shares outstanding. Of these, 1,548,449 were issued to private equity investors and the remainder to management.

In November, 2005, the Company sold 750,000 common shares in a private placement for $75.0 million. In April 2006, the Company sold 333,332 shares in a private placement for $50.0 million. In August 2006 the Company sold 465,117 shares in a private placement for $100.0 million. The August 2006 placement was closed in three separate tranches in August 2006, October 2006 and November 2006. The Company also sold 29,342 shares to management for $3.1 million and sold 91,567 of full recourse note shares for $13.7 million.

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During 2006, the Company sold 166,025 partial recourse (“Partial Recourse Note Shares”) note shares. The Company has accounted for the sale of stock in exchange for partial recourse notes consistent with the accounting for options. Additionally, management was issued 38,595 options. During the six months ended June 30, 2007, an additional 20,175 options were issued.

Full Recourse Note Shares — Full Recourse Note Shares are recorded as shares issued and additional paid in capital. Full recourse note share receivables are secured by security interests in the shares and other collateral granted to the Company by the subscriber under a stock pledge agreement. The balance on the note share receivable is recorded as contra equity. Interest on outstanding balances accrues at 6% per annum but is not recorded until paid. The note shares issued for aggregate consideration of $13.6 million are reflected net of the note share receivable balance at December 31, 2006, of $13.3 million resulting in a $378,750 net increase to stockholders’ equity as of that date and a receivable balance at June 30, 2007 of $13.2 million representing a total net increase to stockholders’ equity of $498,750

Equity-Based Compensation — As discussed in Note 2, the Company adopted SFAS No. 123(R). The stock option plan was adopted during the year ended December 31, 2006. No stock option grants were outstanding in prior years. The fair value of options and Partial Recourse Note Shares is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the options is based on the U.S. treasury yield curve in effect at the time of grant. Since the Company issued its first shares in November 2005 it has no historical information of its own. Therefore, the expected volatility is based on the average of historical unit prices of similar companies. The expected distribution yield is based on projected future distributions. The expected term of options and partial recourse note shares is based on the simplified method and represents the period of time that options granted and partial recourse note shares issued are expected to be outstanding.

Partial Recourse Note Shares — Partial Recourse Note Shares are reflected in stockholders’ equity only to the extent they vest and are accounted for as stock based compensation in the same manner as stock options. Partial Recourse Note Shares vest over an implied seven-year period. The Company recognized non-cash compensation expense of $127,724, $63,820 (unaudited), and $184,110 related to the partial recourse note shares for the six month periods ended June 30, 2007 and 2006 and for the year ended December 31, 2006, respectively.

Stock Options — Stock options were granted during 2006 to management owners and employees. The Company’s stock option plan is designed to promote the interests of stockholders by attracting and retaining employees, nonemployee directors, and consultants by providing the opportunity to purchase common stock of the Company. The plan is administered by the compensation committee of the Company’s Board of Directors. The Company has authorized 150,000 shares of common stock under its stock option plan. Stock options vest over a three-year period ratably at each anniversary of the grant date. A total of 57,570 and 37,995 options were outstanding at June 30, 2007 and December 31, 2006, respectively. Stock options are recorded as stock based compensation and are reflected in stockholders’ equity only to the extent they vest. The Company recognized noncash compensation expense of $275,486, $37,241 (unaudited), and $164,288 related to stock options for the six month periods ended June 30, 2007 and 2006 and for the year ended December 31, 2006.

As of June 30, 2007 and December 31, 2006, the number of shares available for grant under our stock option incentive plan totaled 92,430 and 112,005, respectively.

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A summary of option and Partial Recourse Note Share activity is provided below:


	Number of Shares Underlying Options and Partial Recourse Note Shares			Weighted- Average Exercise Price
Outstanding — January 1, 2006
Granted		204,620		$	113.09
Exercised		—
Forfeited		(600	)	$	150.00

Outstanding — December 31, 2006		204,020			112.98
Granted		20,175		$	215.00
Exercised		—			—
Forfeited		(600	)	$	193.33

Outstanding — June 30, 2007		223,595		$	121.97

Weighted-average remaining contractual term — June 30, 2007		6.6			—
Exercisable options at end of period — June 30, 2007		—			—
Options expected to vest at end of period — June 30, 2007		223,595			121.97
Weighted-average fair value — June 30, 2007		—			12.56

	Year Ended December 31, 2006			Six Month Period June 30, 2007
Weighted-average exercise price	$	113.09		$	121.97
Expected volatility		27.2%-29.1	%		26.7%-29.1	%
Distribution yield		6.8%-11.3	%		6.8%-11.3	%
Risk free interest rate		4.6%-5.2	%		4.6%-5.2	%
Expected term (in years)		3.5-7.0			3.5-7.0
Weighted-average grant date fair value	$	10.02		$	11.62

As of June 30, 2007 and December 31, 2006, unrecognized compensation costs related to outstanding unit options issued under our stock option incentive plan totaled $2.1 and $1.9 million. The expense is expected to be recognized over a weighted-average period of approximately five years.

8.	RELATED-PARTY TRANSACTIONS

Related-Party Long-Term Debt — As discussed in Note 6, the Company has a Credit Agreement with Bank of America, N.A. with an outstanding balance of $20.0 million at June 30, 2007 and December 31, 2006. Bank of America, N.A. is an affiliate of Banc of America Capital Investors SBIC, L.P., an investor in the Company. During the six month periods ended June 30, 2007 and 2006, and the year ended December 31, 2006, the Company incurred interest expense related to the Credit Agreement of $713,403, $163,689 (unaudited), and $1.4 million, respectively. For the same periods above, the Company incurred loan fees of $324,182, $795,281 (unaudited), and $827,462.

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Related-Party Payables — In connection with MEI’s acquisition of MEG from Peak (see Note 4), MEI entered into a $15 million note payable with Peak. At December 31, 2005, the Company had an outstanding balance under this note of $15 million. For the six month period ended June 30, 2006 and the years ended December 2006 and 2005, the Company incurred interest expense of $355,607 (unaudited), $518,657, and $96,164, respectively.

Related-Party Receivables — The Company had two contracts with Peak for the gathering and processing of its natural gas and NGL. For the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005, the Company recorded revenues of $0, $277,566 (unaudited), $557,918 and $464,742, respectively, related to these contracts. These contracts resulted in $72,109 due to the Company from Peak, which is shown as accounts receivable — affiliate, as of December 31, 2005. In May 2006, Peak was sold to an unrelated third party, therefore, there were no related party receivables attributable to these contracts as of December 31, 2006.

During 2006 and 2005, the Company constructed a water pipeline for Peak. The agreement called for the Company to invoice Peak for the cost of the project plus a fee for the cost of overseeing the project. The Company accounted for these revenues on a net basis and recorded construction revenue of $234,500 (unaudited), $236,441, and $263,903 for the six month period ended June 30, 2006, years ended December 31, 2006 and 2005, respectively. At December 31, 2005, the Company had accounts receivable — affiliates of $5.1 million for construction costs on this water pipeline due from Peak.

The Company’s Chairman of the Board is also Chief Executive Officer of an oil and gas exploration and production company that is a Yorktown portfolio company. At June 30, 2007 and December 31, 2006, the Company had a related party receivable from this entity in the amount of $43,871 and $30,364, respectively.

The Company’s executive team has formed another midstream gas company. At June 30, 2007, the company had a related party receivable from this entity in the amount of $9,472.

9.	CUSTOMER INFORMATION

The following tables summarize our significant customer information for the periods indicated:

Percentage of Revenue


Customer	Six Month Period Ended June 30, 2007		Six Month Period Ended June 30, 2006 (Unaudited)		Year Ended December 31, 2006		Year Ended December 31, 2005
Customer A	31	%	59	%	55	%	—	%
Customer B	24		27		20		59
Customer C	12		—		1		—
Customer D	8		—		7		—
Customer E	—		—		1		28
Customer F	—		5		2		9

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Percentage of Cost of Natural Gas and Gas Liquids


Producer	Six Month Period Ended June 30, 2007		Six Month Period Ended June 30, 2006 (Unaudited)		Year Ended December 31, 2006		Year Ended December 31, 2005
Producer A	6	%	—	%	10	%	—	%
Producer B	14		10		9		—
Producer C	8		—		8		—
Producer D	7		—		5		—
Producer E	—		4		—		55
Producer F	—		—		—		26
Producer G	—		10		—		12
Producer H	—		—		—		6
Producer I	4		68		4		—
Producer J	3		6		4		—
Producer K	9		—		1		—

10.

RISK MANAGEMENT ACTIVITIES

The Company, because of the nature of the percent of proceeds contracts in MEG Wyoming and to a lesser extent MEG Texas, is exposed to market risks with respect to the market prices of natural gas and NGL. In general, the Company attempts to hedge the risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The Company does not use derivative instruments for speculative purposes.

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors beyond our control. The Company’s profitability is affected by prevailing commodity prices primarily as a result of the percent of proceeds contracts assigned to the Company with the purchase of the Douglas gathering system. In order to manage the risks associated with natural gas and NGL prices, we engage in risk management activities that take the form of simple market swaps. These swaps allow the Company to sell a set volume of residue gas and the associated NGL at a set price for a set time period. These financial instruments are designated as fair value hedges under SFAS No. 133 and are recorded at fair value on our balance sheet. Changes in fair value are recorded on our consolidated statement of operations. These derivatives are intended to hedge the risk of extreme adverse fluctuations in prices of commodities hedged. For the year ended December 31, 2005, and for the period from August 24, 2004 (date of inception) to

- 20 -

December 31, 2004, the Company had no hedging positions. As of June 30, 2007, the Company had the following hedge positions (dollars in thousands):


		Remaining Term		Pricing Terms	Total Volumes Remaining	Fair Value					Realized Gain (Loss)
		From	To	Pricing Terms	Total Volumes Remaining	June 30, 2007			December 31, 2006		June 30, 2007			December 31, 2006
Natural gas liquids Swaps	Swaps	July 2007	June 2008	Fixed pricing ranging from $0.57 to $1.3975 settling against various daily mean prices as quoted by OPIS.	5,314,383	$	(503	)	$	375	$	(308	)	$	(201	)

Natural gas	Swaps	July 2007	June 2008	Fixed pricing ranging from $6.77 to $7.02 settling against first of month prices as quoted	1,249,850	$	1,503		$	2,246	$	1,462		$	1,343

11.

COMMITMENTS AND CONTINGENCIES

Lease Commitments — The Company is party to several operating lease agreements for its corporate office and its several areas of operations. The Company has entered into operating leases for compressors utilized at its processing plant in Texas.

Future rental payments as of June 30, 2007, are as follows (in thousands):


2007 (remainder)	$	1,076
2008		2,064
2009		2,042
2010		2,033
2011		1,919
Thereafter		3,993

	$	13,127

Rent expense for the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005 and for the period August 24, 2004 (date of inception) to December 31, 2004, were $221,042, $54,595 (unaudited), $221,529, $68,179, and $7,000, respectively. Some office leases contain renewal options and escalation clauses.

Regulatory Compliance — In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management, compliance with existing laws and regulations will not materially affect our financial position.

Insurance — The Company carries insurance coverage on its assets and operations which management believes is consistent with industry practice. These insurance coverages include: (i) commercial general liability for liabilities arising to third parties for bodily injury and property damage; (ii) workers’ compensation liability coverage to required state limits; (iii) automobile liability insurance for all owned, nonowned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (iv) property insurance covering the value of all real and personal property damage, including boiler and machinery; (v) corporate liability policies including directors and officers, employment practice liability, fiduciary liability, and employee dishonesty coverage; and (vi) environmental policies for some of our systems. All policies are subject to certain deductibles, terms, and conditions common for companies with similar types of operation.

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Litigation — The Company may, from time to time, be involved in various legal actions and claims arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial positions of the Company.

12.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of June 30, 2007 and December 31, 2006, the debt associated with the Amended and Restated Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

13.

GAIN ON SALE OF ASSETS

In December 2006, the Company sold a processing plant in exchange for $6.8 million in cash and a pipeline located near our system valued by management with the assistance of a third-party valuation firm at $1.7 million. The Company recorded a gain on the sale of the asset in 2006 of $4.6 million.

14.

EMPLOYEE BENEFIT PLAN

In 2005, the Company began providing a defined contribution benefit plan to its employees. The plan provides for a dollar for dollar matching contribution by the Company on the first 3% of an employee’s contributions and a 50% match on additional employee contributions not to exceed a Company match of 4%. Expenses under the plan for the six month periods ended June 30, 2007 and 2006, the years ended December 31, 2006 and 2005 were approximately $146,760, $61,854 (unaudited) $179,155 and $50,970, respectively.

15.

SUBSEQUENT EVENT

On May 21, 2007 the Company entered into an agreement to sell its stock to DCP Midstream, LLC for $635 million, subject to closing adjustments. Upon closing of the sale, approximately $8.5 to $8.8 million in bonuses and approximately $49.3 million in equity based compensation will be distributed to management and employees.

* * * * * *

- 22 -

Pro Forma Financial Statements of DCP Midstream Partners, LP

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 for the six months ended June 30, 2007 and for 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 Report on Form 10-Q for the quarter ended June 30, 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 sheet as of June 30, 2007, has been prepared as if these transactions had occurred on that date. The unaudited pro forma condensed consolidated statements of operations for the six months ended June 30, 2007, and for 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 purchase price allocation 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.

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
								(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			232.5		372.8		(605.3	)		—			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			—		—		—			161.2	(d)		167.6			—		—			167.6
Other non-current assets		6.3			—		—		—			—			6.3			0.8		(0.8	)(d)		6.3

Total assets	$	587.0		$	259.3	$	431.7	$	(691.0	)	$	163.4		$	750.4		$	313.8	$	(30.2	)	$	1,034.0


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		—			202.3		394.4		(596.7	)		—			—			—		—			—
Stockholders’ equity		—			—		—		—			—			—			228.6		(228.6	)(d)		—
Common unitholders		349.9			—		—		—			27.0	(d)		258.1			—		12.0	(d)		370.1
												(118.8	)(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			202.3		394.4		(596.7	)		(91.2	)		130.0			228.6		(116.6	)		242.0
Less treasury units		(0.2	)		—		—		—			—			(0.2	)		—		—			(0.2	)

Total partners’ equity		221.0			202.3		394.4		(596.7	)		(91.2	)		129.8			228.6		(116.6	)		241.8

Total liabilities and partners’ equity	$	587.0		$	259.3	$	431.7	$	(691.0	)	$	163.4		$	750.4		$	313.8	$	(30.2	)	$	1,034.0

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
										(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			15.7			16.3		(32.0	)		—					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			187.8			104.4		(292.2	)		—					408.6			69.4			(23.5	)				454.5

Operating income		18.4			16.7			11.6		(28.3	)		(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	)		12.2			—			—					12.2
													4.1		(k	)
Other loss		—			—			0.3		(0.3	)		—					—			—			—					—

Income before income taxes		13.0			16.7			13.0		(29.7	)		(4.1	)				8.9			11.2			(8.6	)				11.5
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		$	16.5		$	13.0	$	(29.5	)	$	(4.1	)			$	8.9		$	9.1		$	(7.1	)			$	10.9
Less:
General partner interest in net income		(0.6	)																										(0.6	)

Net income allocable to limited partners	$	12.4																										$	10.3

Net income per limited partner unit — basic and diluted	$	0.60																										$	0.49

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

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
									(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			25.2			24.1		(49.3	)		—			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			436.6			171.7		(608.3	)		—			757.9			59.8			(6.7	)		811.0

Operating income		37.9			48.8			25.6		(74.4	)		—			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)		29.0			—			—			29.0
													11.8	(k)
Other income		—			—			2.1		(2.1	)		—			—			—			—			—

Income before income taxes		33.0			48.8			30.1		(78.9	)		14.7			47.7			6.7			(19.1	)		35.3
Income tax expense		—			(1.8	)		—		1.8			—			—			—			—			—
Non-controlling interest in loss		—			—			—		—			—			—			0.1			—			0.1

Net income	$	33.0		$	47.0		$	30.1	$	(77.1	)	$	14.7		$	47.7		$	6.8		$	(19.1	)	$	35.4
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																						$	36.9


Net income per limited partner unit — basic and diluted	$	1.90																						$	1.75


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 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. 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 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:


Cash consideration	$	243.7
Common units		27.0
General partner equivalent units		0.6

Aggregate consideration		271.3
Historical cost of interest in the East Texas Midstream Business		(50.6	)
Historical cost of interest in Discovery		(110.6	)
Historical cost of the Swap		8.7

Adjustment to net parent equity for excess consideration	$	118.8

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, the Outside Basis in Discovery was a deficit of $46.1 million.

The historical cost of the Swap consists of a current liability of $2.4 million and a long-term liability of $6.3 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.

(f)

Reflects losses from non-trading derivative activity — affiliates 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
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		Year Ended December 31, 2006
Our share of Discovery’s historical net income	$	5.2	$	12.0
Amortization of the Outside Basis		2.4		4.9

Increase in earnings from equity method investments	$	7.6	$	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, we did not allocate additional earnings to the general partner. For the year ended December 31, 2006, our pro forma aggregate net income per unit exceeded certain distribution levels, and as a result we allocated $0.5 million 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;

•

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			Year Ended December 31, 2006
Pro forma net income	$	10.9		$	35.4
Less: net loss attributable to predecessor operations		—			2.3

Pro forma net income attributable to partnership		10.9			37.7
Less: general partner interest in net income		(0.6	)		(0.8	)

Pro forma limited partners’ interest in net income		10.3			36.9
Less: additional earnings allocated to general partner		—			(0.5	)

Pro forma net income available to limited partners	$	10.3		$	36.4

Pro forma net income per LPU — basic and diluted	$	0.49		$	1.75