Consolidated Financial Statements of DCP Midstream Partners, LP

EX-99.3 6 dex993.htm CONSOLIDATED FINANCIAL STATEMENTS OF DCP MIDSTREAM PARTNERS, LP Consolidated Financial Statements of DCP Midstream Partners, LP

Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

DCP Midstream Partners GP, LLC

Denver, Colorado:

We have audited the accompanying consolidated balance sheets of DCP Midstream Partners, LP and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, comprehensive income, changes in partners’ equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. The consolidated financial statements give retroactive effect to the acquisition of a 25% limited liability interest in DCP East Texas Holdings, LLC (“East Texas”), a 40% limited liability interest in Discovery Producer Services LLC (“Discovery”), and a nontrading derivative instrument (the “Swap”) from DCP Midstream, LLC (“Midstream”) by the Company on July 1, 2007, which has been accounted for in a manner similar to a pooling of interests as described in Note 4 to the consolidated financial statements. We did not audit the financial statements of Discovery, an investment of the Company which is accounted for by the use of the equity method. The Company’s equity in Discovery’s net assets of $162,040,000 and $155,298,000 at December 31, 2006 and 2005, respectively, and in Discovery’s net income of $12,033,000, $6,909,000, and $3,890,000 for the years ended December 31, 2006, 2005 and 2004, respectively, are included in the accompanying consolidated financial statements. Discovery’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to amounts included for Discovery, is based solely on the report of such other auditors.

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, after giving retroactive effect to the acquisition of East Texas, Discovery, and the Swap as described in Note 4 to the consolidated financial statements, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule when considered with the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company was formed on December 7, 2005 and began operating as a separate entity. Through December 7, 2005 the accompanying consolidated financial statements 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 Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Midstream as a whole.

The consolidated financial statements also give retroactive effect to the November 1, 2006 acquisition by the Company of the wholesale propane logistics business which, as a combination of entities under common control, has been accounted for similar to a pooling of interests as described in Note 4 to the consolidated financial statements. Also as described in Note 1 to the consolidated financial statements, through November 1, 2006, the portion of the accompanying consolidated financial statements attributable to the wholesale propane logistics business, have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed or the results of operations if the wholesale propane logistics business had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to Midstream as a whole.

Also as described in Note 1 to the consolidated financial statements, the portion of the accompanying consolidated financial statements attributable to East Texas, Discovery and the Swap have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed or the results of operations if East Texas, Discovery and the Swap had been operated as unaffiliated entities. Portions of certain expenses represent allocations made from, and are applicable to Midstream as a whole.

/s/ Deloitte & Touche LLP

Denver, Colorado

October 16, 2007

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

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS


	June 30, 2007			December 31,
	June 30, 2007			2006			2005
	(unaudited)
	($ in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	55.0		$	46.2		$	42.2
Short-term investments		—			0.6			—
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.6 million (unaudited), $0.3 million and $0.3 million, respectively		40.2			43.4			65.7
Affiliates		30.4			34.8			56.5
Inventories		30.3			30.1			41.7
Unrealized gains on non-trading derivative and hedging instruments		3.2			4.2			0.2
Other		0.2			0.3			0.1

Total current assets		159.3			159.6			206.4
Restricted investments		—			102.0			100.4
Property, plant and equipment, net		370.7			194.7			178.7
Goodwill		29.3			29.3			29.3
Intangible assets, net		15.0			2.8			3.2
Equity method investments		168.4			170.2			155.7
Unrealized gains on non-trading derivative and hedging instruments		5.0			6.5			5.4
Other non-current assets		1.3			0.8			1.0

Total assets	$	749.0		$	665.9		$	680.1

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	70.7		$	66.9		$	95.9
Affiliates		21.6			50.4			42.4
Unrealized losses on non-trading derivative and hedging instruments		6.8			0.7			2.7
Accrued interest payable		0.4			1.1			0.8
Other		7.3			7.4			4.5

Total current liabilities		106.8			126.5			146.3
Long-term debt		249.0			268.0			210.1
Unrealized losses on non-trading derivative and hedging instruments		16.6			2.7			2.5
Other long-term liabilities		2.3			1.0			0.5

Total liabilities		374.7			398.2			359.4

Commitments and contingent liabilities
Partners’ equity:
Predecessor equity		153.3			164.3			219.8
Common unitholders (13,362,923, 10,357,143 and 10,357,143 units issued and outstanding, respectively)		349.9			223.4			215.8
Class C unitholders (200,312, 200,312 and 0 units issued and outstanding, respectively)		(20.7	)		(20.7	)		—
Subordinated unitholders (7,142,857 convertible units issued and outstanding at all periods)		(102.5	)		(101.6	)		(109.7	)
General partner interest		(5.0	)		(5.0	)		(5.6	)
Accumulated other comprehensive income		(0.5	)		7.3			0.4

Total		374.5			267.7			320.7
Less treasury units, at cost (4,000, 0 and 0, respectively)		(0.2	)		—			—

Total partners’ equity		374.3			267.7			320.7

Total liabilities and partners’ equity	$	749.0		$	665.9		$	680.1

See accompanying notes to consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
	(unaudited)
	($ in millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	301.9		$	291.6		$	535.1		$	1,004.6		$	729.8
Sales of natural gas, propane, NGLs and condensate to affiliates		116.6			121.0			232.8			117.5			85.6
Transportation and processing services		6.9			7.4			15.0			12.5			9.5
Transportation and processing services to affiliates		7.9			6.0			12.8			10.6			11.0
Losses from non-trading derivative activity, net		(14.5	)		—			—			—			—
(Losses) gains from non-trading derivative activity — affiliates		(0.5	)		(0.5	)		0.1			(0.9	)		(1.9	)

Total operating revenues		418.3			425.5			795.8			1,144.3			834.0

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		292.6			324.3			581.2			889.5			644.2
Purchases of natural gas, propane and NGLs from affiliates		83.5			55.6			119.2			157.8			116.4
Operating and maintenance expense		12.9			11.5			23.7			22.4			19.8
Depreciation and amortization expense		7.9			6.4			12.8			12.7			14.7
General and administrative expense		7.0			5.5			12.9			5.1			0.9
General and administrative expense — affiliates		4.7			3.8			8.1			9.1			7.8

Total operating costs and expenses		408.6			407.1			757.9			1,096.6			803.8

Operating income		9.7			18.4			37.9			47.7			30.2
Interest income		2.5			3.0			6.3			0.5			—
Interest expense		(8.4	)		(5.2	)		(11.5	)		(0.8	)		—
Earnings from equity method investments		12.8			15.8			29.2			25.7			17.6
Impairment of equity method investment		—			—			—			—			(4.4	)

Income before income taxes		16.6			32.0			61.9			73.1			43.4
Income tax expense		—			—			—			3.3			2.5

Net income	$	16.6		$	32.0		$	61.9		$	69.8		$	40.9
Less:
Net income attributable to predecessor operations		(3.6	)		(17.8	)		(26.6	)		(65.1	)		(40.9	)
General partner interest in net income		(0.6	)		(0.3	)		(0.7	)		(0.1	)		—

Net income allocable to limited partners	$	12.4		$	13.9		$	34.6		$	4.6		$	—

Net income per limited partner unit — basic and diluted	$	0.60		$	0.79		$	1.90		$	0.20		$	—

Weighted-average limited partner units outstanding — basic and diluted		17.8			17.5			17.5			17.5			—

See accompanying notes to consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005		2004
	(unaudited)
	($ in millions)
Net income	$	16.6		$	32.0		$	61.9		$	69.8	$	40.9

Other comprehensive income:
Reclassification of cash flow hedges into earnings		(2.1	)		(0.7	)		(2.7	)		—		—
Net unrealized (losses) gains on cash flow hedges		(5.7	)		(2.8	)		9.6			0.4		—

Total other comprehensive income		(7.8	)		(3.5	)		6.9			0.4		—

Total comprehensive income	$	8.8		$	28.5		$	68.8		$	70.2	$	40.9

See accompanying notes to consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ EQUITY


	Predecessor Equity			Treasury Units			Common Unitholders			Class C Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income			Total Partners’ Equity
	($ in millions)
Balance, January 1, 2004	$	395.1		$	—		$	—		$	—		$	—		$	—		$	—		$	395.1
Net change in parent advances		(35.5	)		—			—			—			—			—			—			(35.5	)
Net income attributable to predecessor operations		40.9			—			—			—			—			—			—			40.9

Balance, December 31, 2004		400.5			—			—			—			—			—			—			400.5
Net change in parent advances		(137.7	)		—			—			—			—			—			—			(137.7	)
Proceeds from initial public offering of 10,350,000 common units		—			—			222.5			—			—			—			—			222.5
Underwriters’ discount and offering expenses		—			—			(9.3	)		—			(6.4	)		(0.4	)		—			(16.1	)
Distribution to unitholders		(218.7	)		—			—			—			—			—			—			(218.7	)
Allocation of predecessor equity in exchange for 7,143 common units, 7,142,857 subordinated units and a 2% general partnership interest (represented by 357,143 equivalent units)		110.6			—			(0.1	)		—			(105.2	)		(5.3	)		—			—
Net income attributable to predecessor operations		65.1			—			—			—			—			—			—			65.1
Net income from December 7, 2005 through December 31, 2005		—			—			2.7			—			1.9			0.1			—			4.7
Other comprehensive income		—			—			—			—			—			—			0.4			0.4

Balance, December 31, 2005		219.8			—			215.8			—			(109.7	)		(5.6	)		0.4			320.7
Net change in parent advances		(25.4	)		—			—			—			—			—			—			(25.4	)
Acquisition of wholesale propane logistics business		(56.7	)		—			—			—			—			—			—			(56.7	)
Excess purchase price over acquired assets		—			—			—			(26.3	)		—			—			—			(26.3	)
Issuance of 200,312 Class C units		—			—			—			5.6			—			—			—			5.6
Proceeds from general partner interest (represented by 4,088 equivalent units)		—			—			—			—			—			0.1			—			0.1
Contributions by unitholders		—			—			—			—			2.8			0.2			—			3.0
Distributions to unitholders		—			—			(12.8	)		(0.1	)		(8.8	)		(0.4	)		—			(22.1	)
Net income attributable to predecessor operations		26.6			—			—			—			—			—			—			26.6
Net income		—			—			20.4			0.1			14.1			0.7			—			35.3
Other comprehensive income		—			—			—			—			—			—			6.9			6.9

Balance, December 31, 2006		164.3			—			223.4			(20.7	)		(101.6	)		(5.0	)		7.3			267.7
Net change in parent advances		(14.6	)		—			—			—			—			—			—			(14.6	)
Purchase of treasury units		—			(0.2	)		—			—			—			—			—			(0.2	)
Issuance of common units		—			—			128.5			—			—			—			—			128.5
Contributions by unitholders		—			—			—			—			0.4			—			—			0.4
Distributions to unitholders		—			—			(9.2	)		(0.2	)		(6.4	)		(0.6	)		—			(16.4	)
Equity-based compensation		—			—			0.1			—			—			—			—			0.1
Net income attributable to predecessor operations		3.6			—			—			—			—			—			—			3.6
Net income		—			—			7.1			0.2			5.1			0.6			—			13.0
Other comprehensive income		—			—			—			—			—			—			(7.8	)		(7.8	)

Balance, June 30, 2007 (unaudited)	$	153.3		$	(0.2	)	$	349.9		$	(20.7	)	$	(102.5	)	$	(5.0	)	$	(0.5	)	$	374.3

See accompanying notes to consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
	(unaudited)
	($ in millions)
OPERATING ACTIVITIES:
Net income	$	16.6		$	32.0		$	61.9		$	69.8		$	40.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense and impairment charge		7.9			6.4			12.8			12.7			19.1
Earnings from equity method investments, net of distributions		5.7			(4.7	)		(3.3	)		11.0			(4.2	)
Deferred income tax benefit		—			—			—			(0.5	)		(0.1	)
Other, net		(0.4	)		(1.4	)		(2.4	)		0.1			(0.2	)
Change in operating assets and liabilities which provided (used) cash:
Accounts receivable		9.8			73.9			43.1			(30.7	)		(19.0	)
Inventories		(0.2	)		12.4			11.6			(21.0	)		0.2
Net unrealized losses (gains) on non-trading derivative and hedging instruments		14.9			0.9			(0.1	)		0.1			0.3
Accounts payable		(14.2	)		(83.0	)		(31.5	)		74.7			0.8
Accrued interest		(0.7	)		(0.2	)		0.3			0.8			—
Income tax payable		—			—			—			(3.2	)		(0.1	)
Other current assets and liabilities		(0.2	)		1.7			2.0			(0.7	)		0.4
Other non-current assets and liabilities		0.6			—			0.4			(0.1	)		—

Net cash provided by operating activities		39.8			38.0			94.8			113.0			38.1

INVESTING ACTIVITIES:
Capital expenditures		(7.6	)		(12.1	)		(27.2	)		(10.8	)		(3.3	)
Acquisition of assets		(191.3	)		—			—			—			—
Acquisition of wholesale propane logistics business		—			—			(56.7	)		—			—
Investments in equity method investees		(3.9	)		(7.4	)		(11.1	)		(20.5	)		—
Payment of earnest deposit		(9.0	)		—			—			—			—
Refund of earnest deposit		9.0			—			—			—			—
Proceeds from sales of assets		0.1			0.1			0.3			1.2			0.7
Purchases of available-for-sale securities		(6,427.7	)		(4,249.8	)		(7,372.4	)		(731.0	)		—
Proceeds from sales of available-for-sale securities		6,531.1			4,248.8			7,373.3			630.8			—
Other investing activities		—			—			—			(0.1	)		—

Net cash used in investing activities		(99.3	)		(20.4	)		(93.8	)		(130.4	)		(2.6	)

FINANCING ACTIVITIES:
Borrowings under debt facilities		188.0			—			78.0			210.1			—
Repayments of debt		(207.0	)		(20.1	)		(20.1	)		—			—
Payment of deferred financing costs		(0.5	)		—			(0.2	)		(0.5	)		—
Proceeds from issuance of common units, net of offering costs		128.5			—			—			206.4			—
Proceeds from issuance of equivalent units to general partner		—			—			0.1			—			—
Purchase of treasury units		(0.2	)		—			—			—			—
Excess purchase price over acquired assets		(9.9	)		—			(10.7	)		—			—
Net change in advances from DCP Midstream, LLC		(14.6	)		(14.6	)		(25.4	)		(137.7	)		(35.5	)
Distributions to unitholders		(16.4	)		(8.0	)		(22.1	)		(218.7	)		—
Contributions from unitholders		0.4			3.2			3.4			—			—

Net cash provided by (used in) financing activities		68.3			(39.5	)		3.0			59.6			(35.5	)

Net change in cash and cash equivalents		8.8			(21.9	)		4.0			42.2			—
Cash and cash equivalents, beginning of period		46.2			42.2			42.2			—			—

Cash and cash equivalents, end of period	$	55.0		$	20.3		$	46.2		$	42.2		$	—

Supplementary disclosure of cash flow information:
Cash paid for interest expense, net of capitalized interest	$	10.0		$	5.4		$	11.1		$	—		$	—
Cash paid for income taxes	$	—		$	—		$	—		$	2.6		$	2.7

See accompanying notes to consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Six Months Ended June 30, 2007 and 2006 (unaudited)

and Years Ended December 31, 2006, 2005 and 2004

1. Description of Business and Basis of Presentation

DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we or our, is engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and the business of producing, transporting and selling propane and natural gas liquids, or NGLs.

We are a Delaware master limited partnership that was formed in August 2005. We completed our initial public offering on December 7, 2005. Our partnership includes: our Northern Louisiana system assets; our Southern Oklahoma system (which was acquired in May 2007); our NGL transportation pipelines; and our wholesale propane logistics business (which was acquired in November 2006).

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to us and operate or manage the operation of our assets. DCP Midstream, LLC owns in aggregate an approximate 35% interest in our partnership.

The consolidated financial statements include our accounts, and prior to December 7, 2005 the assets, liabilities and operations contributed to us by DCP Midstream, LLC and its wholly-owned subsidiaries, which we refer to as DCP Midstream Partners Predecessor, upon the closing of our initial public offering.

In November 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC in a transaction among entities under common control. Accordingly, our financial information includes the historical results of our wholesale propane logistics business for all periods presented.

In July 2007, we acquired our 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery, and our non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, from DCP Midstream, LLC in a transaction among entities under common control. Accordingly, these consolidated financial statements include the historical results of the equity interest in East Texas and Discovery, and the historical results of the Swap, for all periods presented.

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. We refer to DCP Midstream Partners Predecessor, the assets, liabilities and operations of our wholesale propane logistics business prior to our acquisition from DCP Midstream, LLC in November 2006, our equity interests in East Texas and Discovery, and the Swap, collectively as our “predecessors.” The consolidated financial statements of our predecessors have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as an unaffiliated entity. All significant intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates. The accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly these consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods.

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 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.

Reclassifications — Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.

Cash and Cash Equivalents — We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less to be cash equivalents.

Short-Term and Restricted Investments — Short-term investments consist of $0.6 million at December 31, 2006. We had no short-term investments at June 30, 2007 (unaudited) or December 31, 2005. We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted.

Restricted investments consist of $102.0 million and $100.4 million in investments in commercial paper and various other high-grade debt securities at December 31, 2006 and 2005, respectively. These investments are used as collateral to secure the term loan portion of our credit facility and to finance gathering and compression asset acquisitions. There were no restricted investments as of June 30, 2007 unaudited.

We have classified all short-term and restricted investments as available-for-sale as we do not intend to hold them to maturity, nor are they bought or sold with the objective of generating profit on short-term differences in prices. These investments are recorded at fair value, with changes in fair value recorded as unrealized gains and losses in accumulated other comprehensive income, or AOCI. No gains or losses were deferred in AOCI at June 30, 2007 (unaudited), December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us, and as interest rates are re-set on a daily, weekly or monthly basis.

Gas and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash.

Included in the consolidated balance sheets as accounts receivable—trade, were imbalances of $0.2 million (unaudited), $0.1 million and $1.1 million at June 30, 2007, December 31, 2006 and 2005, respectively. Included in the consolidated balance sheets as accounts payable—trade, were imbalances of $1.3 million (unaudited), $0.9 million and $2.5 million at June 30, 2007, December 31, 2006 and 2005, respectively.

Inventories — Inventories consist primarily of propane. Inventories are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory on the consolidated balance sheets.

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.

Goodwill and Intangible Assets — Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. The goodwill on the consolidated balance sheets was recognized by DCP Midstream, LLC when it acquired certain assets which are now included in the wholesale propane logistics business, and was allocated based on fair value to the wholesale propane logistics business in order to present historical information about the assets we acquired. We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

Intangible assets consist primarily of commodity contracts. The commodity contracts are amortized on a straight-line basis over the period of expected future benefit, ranging from approximately five to 25 years.

Equity Method Investments — We account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, under the equity method.

We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.

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.

Unamortized Debt Expense — Expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These expenses are recorded on the consolidated balance sheet as other non-current assets.

Accounting for Risk Management and Hedging Activities and Financial Instruments — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We will use the mark-to-market method of accounting for all commodity cash flow hedges beginning in July 2007. As a result, the remaining net loss of $2.0 million (unaudited) deferred in accumulated other comprehensive income, or AOCI, as of June 30, 2007 will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings

Each derivative not qualifying as a normal purchase or normal sales is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on non-trading derivative and hedging instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on non-trading derivative and hedging instruments at fair value until the contractual settlement period impacts earnings.

All derivative activity reflected in the consolidated financial statements for our predecessors was transacted by us or by DCP Midstream, LLC and its subsidiaries, and transferred and/or allocated to us. All derivative activity reflected in the consolidated financial statements, which is not related to our predecessors, has been and will be transacted by us, although DCP Midstream, LLC personnel execute various transactions on our behalf. We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales, while certain non-trading derivatives, which are related to asset-based activities, are designated as non-trading derivative activity. For the periods presented, we did not have any trading derivative activity, however, we do have cash flow and fair value hedge activity, normal purchases and normal sales activity, and non-trading derivative activity included in the consolidated financial statements. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:


Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity	Mark-to-market method (a)	Net basis in (losses) gains from non-trading derivative activity

Cash Flow Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (c)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

(a)	Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in (losses) gains from non-trading derivative activity during the current period.

(b)

Hedge method — An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on non-trading derivative and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.

(c)	Accrual method — An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.

Cash Flow and Fair Value Hedges — For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess, both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on non-trading derivative and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in partners’ equity as AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same accounts as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on non-trading derivative and hedging instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.

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

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

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

•

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

•

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

•

Propane sales arrangements — Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to retail propane distributors, who in turn resell to their retail customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their retail customers.

Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.

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

•

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

Significant Customer — We had one customer, a third party, that accounted for 17% and 18% of total operating revenues for the years ended December 31, 2005 and 2004, respectively. Revenues from this customer are reported in the NGL Logistics Segment. There were no customers that accounted for more than 10% of total operating revenues for the six months ended June 30, 2007 (unaudited) or for the year ended December 31, 2006. We also had significant transactions with affiliates, and with suppliers of propane (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

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 (unaudited), December 31, 2006 and 2005, included in the consolidated balance sheets as other current liabilities, were not significant.

Equity-Based Compensation — Under the DCP Midstream Partners, LP Long-Term Incentive Plan, or the LTIP, equity instruments may be granted to our key employees. The General Partner adopted the LTIP for employees, consultants and directors of the General Partner and its affiliates who perform services for us. The LTIP provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the LTIP. Awards that are cancelled, forfeited or are withheld to satisfy the General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the General Partner’s board of directors. Awards were first granted under the LTIP during 2006.

Equity classified stock-based compensation cost is measured at grant date, based on the estimated fair value of the award, and is recognized as expense over the vesting period. Liability classified stock-based compensation cost is remeasured at each reporting date and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Awards granted to non-employees for acquiring, or in conjunction with selling, goods and services, are measured at the estimated fair value of the goods or services, or the fair value of the award, whichever is more reliably measured.

Income Taxes — We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our wholesale propane logistics business changed its tax structure, effective December 7, 2005, such that it became a pass-through entity. Prior to December 7, 2005, our wholesale propane logistics business was considered taxable for United States income tax purposes. Our wholesale propane logistics business followed the asset and liability method of accounting for income taxes, whereby deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Subsequent to December 7, 2005, our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is includable in the federal returns of each partner.

Comprehensive Income — Comprehensive income consists of net income and other comprehensive income, which includes unrealized gains and losses on the effective portion of derivative instruments classified as cash flow hedges.

Net Income per Limited Partner Unit — Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions by the weighted-average number of outstanding limited partner units during the period.

3. New Accounting Standards

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 consolidated results of operations, cash flows or financial position.

SFAS No. 157, Fair Value Measurements, or SFAS 157 — In September 2006, the FASB issued SFAS 157, which 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 consolidated results of operations, cash flows or financial position.

SFAS No. 154, Accounting Changes and Error Corrections, or SFAS 154 — In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also: (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle; and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.

FASB Interpretation Number, or FIN, 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. The adoption of FIN 48 did not have a material impact on our consolidated 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 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108 — In September 2006, the Securities and Exchange Commission, or SEC, issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.

4. Acquisitions

Gathering and Compression Assets

On July 1, 2007, we acquired a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery and the Swap from DCP Midstream, LLC for aggregate consideration of approximately $271.3 million, consisting of approximately $243.7 million in cash, including net working capital of $1.3 million and other adjustments, the issuance of 620,404 common units valued at $27.0 million and the issuance of 12,661 general partner equivalent units valued at $0.6 million. We financed the cash portion of this transaction with borrowings of $245.9 million under our amended credit facility. The transfer of assets between DCP Midstream, LLC and us represents a transfer of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. The $118.0 million excess purchase price over the historical basis of the net aquired assets will be recorded as a reduction to partners’ equity, and the $27.6 million of common and general partner equivalent units issued as partial consideration for this transaction will be recorded as an increase to partners’ equity, for financial accounting purposes.

In May 2007, we agreed to acquire certain subsidiaries of Momentum Energy Group Inc., or MEG, from DCP Midstream, LLC for $165.0 million, subject to closing adjustments. This transaction closed in the third quarter of 2007. The purchase price consisted of approximately $153.8 million of cash and the issuance of 275,735 common units to an affiliate of DCP Midstream, LLC that were valued at approximately $12.0 million. We have incurred post-closing purchase price adjustments to date that include a liability of $9.0 million for net working capital and general and administrative charges. We financed this transaction with $120.0 million of borrowings under our amended credit facility, the issuance of common units and cash on hand. On May 21, 2007, in connection with this acquisition, DCP Partners entered into a common unit purchase agreement with certain institutional investors to sell 2,380,952 common limited partner units in a private placement at $42.00 per unit, or approximately $100.0 million in the aggregate. In connection with this common unit purchase agreement, DCP Partners has a registration rights agreement to file a shelf registration statement with the SEC to register the units within 90 days of the close of the private placement. In, addition the registration rights agreement requires DCP Partners to use its commercially reasonable efforts to cause the registration statement to become effective within 180 days of the closing of the private placement. If the registration statement covering the common units is not declared effective by the SEC within 180 days of the closing of the private placement, then DCP Partners will be liable to the purchasers for liquidated damages of 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for the first 60 days following the 180th day, increasing by an additional 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period.

In May 2007, we acquired certain gathering and compression assets located in Southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181.1 million (unaudited).

In April 2007, we acquired certain gathering and compression assets located in Northern Louisiana from Laser Gathering Company, LP for approximately $10.2 million (unaudited), subject to customary purchase price adjustments.

The results of operations for these acquired assets have been, or will be, included prospectively, from the dates of acquisition, as part of the Natural Gas Services segment.

Wholesale Propane Logistics Business

On November 1, 2006, we acquired our wholesale propane logistics business, from DCP Midstream, LLC for aggregate consideration consisting of approximately $82.9 million, which consisted of $77.3 million in cash ($9.9 million of which was paid in January 2007), and the issuance of 200,312 Class C units valued at approximately $5.6 million. Included in the aggregate consideration was $10.5 million of costs associated with the construction of a new propane pipeline terminal.

The transfer of assets between DCP Midstream, LLC and us represents a transfer of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. The $26.3 million excess purchase price over the historical basis of the net acquired assets was recorded as a reduction to partners’ equity, and the $5.6 million of Class C units issued as partial consideration for this transaction were recorded as an increase to partners’ equity, for financial accounting purposes.

Results

The following tables present the impact on the consolidated balance sheets, adjusted for the acquisition of our wholesale propane logistics business, and for the acquisition of East Texas, Discovery and the Swap, from DCP Midstream, LLC ($ in millions):

As of June 30, 2007 (unaudited)


	DCP Midstream Partners, LP			East Texas, Discovery and the Swap		Combined DCP Midstream Partners, LP
ASSETS
Current assets:
Cash and cash equivalents	$	55.0		$	—	$	55.0
Accounts receivable		70.6			—		70.6
Inventories		30.3			—		30.3
Other		3.4			—		3.4

Total current assets		159.3			—		159.3
Restricted investments		—			—		—
Property, plant and equipment, net		370.7			—		370.7
Goodwill and intangible assets, net		44.3			—		44.3
Other non-current assets		12.7			162.0		174.7

Total assets	$	587.0		$	162.0	$	749.0

LIABILITIES AND PARTNERS’ EQUITY
Accounts payable and other current liabilities	$	104.4		$	2.4	$	106.8
Long-term debt		249.0			—		249.0
Other long-term liabilities		12.6			6.3		18.9

Total liabilities		366.0			8.7		374.7

Commitments and contingent liabilities
Partners’ equity:
Net equity		221.5			153.3		374.8
Accumulated other comprehensive loss		(0.5	)		—		(0.5	)

Total partners’ equity		221.0			153.3		374.3

Total liabilities and partners’ equity	$	587.0		$	162.0	$	749.0

As of December 31, 2006


	DCP Midstream Partners, LP		East Texas and Discovery		Combined DCP Midstream Partners, LP
ASSETS
Current assets:
Cash and cash equivalents	$	46.2	$	—	$	46.2
Accounts receivable		78.2		—		78.2
Inventories		30.1		—		30.1
Other		5.1		—		5.1

Total current assets		159.6		—		159.6
Restricted investments		102.0		—		102.0
Property, plant and equipment, net		194.7		—		194.7
Goodwill and intangible assets, net		32.1		—		32.1
Other non-current assets		13.2		164.3		177.5

Total assets	$	501.6	$	164.3	$	665.9

LIABILITIES AND PARTNERS’ EQUITY
Accounts payable and other current liabilities	$	126.5	$	—	$	126.5
Long-term debt		268.0		—		268.0
Other long-term liabilities		3.7		—		3.7

Total liabilities		398.2		—		398.2

Commitments and contingent liabilities
Partners’ equity:
Net equity		96.1		164.3		260.4
Accumulated other comprehensive income		7.3		—		7.3

Total partners’ equity		103.4		164.3		267.7

Total liabilities and partners’ equity	$	501.6	$	164.3	$	665.9

As of December 31, 2005


	DCP Midstream Partners, LP		Wholesale Propane Logistics Business		East Texas and Discovery		Combined DCP Midstream Partners, LP
ASSETS
Current assets:
Cash and cash equivalents	$	42.2	$	—	$	—	$	42.2
Accounts receivable		82.0		40.2		—		122.2
Inventories		0.1		41.6		—		41.7
Other		0.2		0.1		—		0.3

Total current assets		124.5		81.9		—		206.4
Restricted investments		100.4		—		—		100.4
Property, plant and equipment, net		168.9		9.8		—		178.7
Goodwill and intangible assets, net		2.1		30.4		—		32.5
Other non-current assets		11.4		0.5		150.2		162.1

Total assets	$	407.3	$	122.6	$	150.2	$	680.1

LIABILITIES AND PARTNERS’ EQUITY
Accounts payable and other current liabilities	$	93.4	$	52.9	$	—	$	146.3
Long-term debt		210.1		—		—		210.1
Other long-term liabilities		2.9		0.1		—		3.0

Total liabilities		306.4		53.0		—		359.4

Commitments and contingent liabilities
Partners’ equity:
Net equity		100.5		69.6		150.2		320.3
Accumulated other comprehensive income		0.4		—		—		0.4

Total partners’ equity		100.9		69.6		150.2		320.7

Total liabilities and partners’ equity	$	407.3	$	122.6	$	150.2	$	680.1

The following tables present the impact on the consolidated statements of operations, adjusted for the acquisition of our wholesale propane logistics business, and for the acquisition of East Texas, Discovery and the Swap, from DCP Midstream, LLC, for the periods presented ($ in millions):

Six Months Ended June 30, 2007 (unaudited)


	DCP Midstream Partners, LP			East Texas, Discovery and the Swap			Combined DCP Midstream Partners, LP
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	418.5		$	—		$	418.5
Transportation and other		8.5			(8.7	)		(0.2	)

Total operating revenues		427.0			(8.7	)		418.3

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		376.1			—			376.1
Operating and maintenance expense		12.9			—			12.9
Depreciation and amortization expense		7.9			—			7.9
General and administrative expense		11.7			—			11.7

Total operating costs and expenses		408.6			—			408.6

Operating income		18.4			(8.7	)		9.7
Interest expense, net		(5.9	)		—			(5.9	)
Earnings from equity method investments		0.5			12.3			12.8

Net income	$	13.0		$	3.6		$	16.6

Six Months Ended June 30, 2006 (unaudited)


	DCP Midstream Partners, LP			Wholesale Propane Logistics Business			East Texas and Discovery		Combined DCP Midstream Partners, LP
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	201.6		$	211.0		$	—	$	412.6
Transportation and other		13.4			(0.5	)		—		12.9

Total operating revenues		215.0			210.5			—		425.5

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		177.8			202.1			—		379.9
Operating and maintenance expense		7.3			4.2			—		11.5
Depreciation and amortization expense		5.9			0.5			—		6.4
General and administrative expense		7.7			1.6			—		9.3

Total operating costs and expenses		198.7			208.4			—		407.1

Operating income		16.3			2.1			—		18.4
Interest expense, net		(2.2	)		—			—		(2.2	)
Earnings from equity method investments		0.1			—			15.7		15.8

Net income	$	14.2		$	2.1		$	15.7	$	32.0

Year Ended December 31, 2006


	DCP Midstream Partners, LP and Predecessor			East Texas and Discovery		Combined DCP Midstream Partners, LP
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	767.9		$	—	$	767.9
Transportation and other		27.9			—		27.9

Total operating revenues		795.8			—		795.8

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		700.4			—		700.4
Operating and maintenance expense		23.7			—		23.7
Depreciation and amortization expense		12.8			—		12.8
General and administrative expense		21.0			—		21.0

Total operating costs and expenses		757.9			—		757.9

Operating income		37.9			—		37.9
Interest expense, net		(5.2	)		—		(5.2	)
Earnings from equity method investments		0.3			28.9		29.2
Income tax expense		—			—		—

Net income	$	33.0		$	28.9	$	61.9

Year Ended December 31, 2005


	DCP Midstream Partners, LP and Predecessor			Wholesale Propane Logistics Business			East Texas and Discovery		Combined DCP Midstream Partners, LP
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	762.3		$	359.8		$	—	$	1,122.1
Transportation and other		22.2			—			—		22.2

Total operating revenues		784.5			359.8			—		1,144.3

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		709.3			338.0			—		1,047.3
Operating and maintenance expense		14.2			8.2			—		22.4
Depreciation and amortization expense		11.7			1.0			—		12.7
General and administrative expense		11.4			2.8			—		14.2

Total operating costs and expenses		746.6			350.0			—		1,096.6

Operating income		37.9			9.8			—		47.7
Interest expense, net		(0.3	)		—			—		(0.3	)
Earnings from equity method investments		0.4			—			25.3		25.7
Income tax expense		—			(3.3	)		—		(3.3	)

Net income	$	38.0		$	6.5		$	25.3	$	69.8

Year Ended December 31, 2004


	DCP Midstream Partners, LP and Predecessor			Wholesale Propane Logistics Business			East Texas and Discovery		Combined DCP Midstream Partners, LP
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	489.7		$	325.7		$	—	$	815.4
Transportation and other		19.8			(1.2	)		—		18.6

Total operating revenues		509.5			324.5			—		834.0

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		452.6			308.0			—		760.6
Operating and maintenance expense		13.6			6.2			—		19.8
Depreciation and amortization expense		12.6			2.1			—		14.7
General and administrative expense		6.5			2.2			—		8.7

Total operating costs and expenses		485.3			318.5			—		803.8

Operating income		24.2			6.0			—		30.2
Earnings from equity method investments		0.6			—			17.0		17.6
Impairment of equity method investment		(4.4	)		—			—		(4.4	)
Income tax expense		—			(2.5	)		—		(2.5	)

Net income	$	20.4		$	3.5		$	17.0	$	40.9

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

DCP Midstream, LLC provided centralized corporate functions on behalf of our predecessor operations, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The predecessor’s share of those costs was allocated based on the predecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investments, and intangible assets, net) as compared to DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used were reasonable and resulted in an allocation to the predecessors of their respective costs of doing business, which were borne by DCP Midstream, LLC.

Omnibus Agreement

We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Omnibus Agreement: (1) states that the annual fee of $4.8 million for the initial assets under the agreement was fixed at such amount for 2006, subject to annual increases in the Consumer Price Index, which increased to $5.0 million for 2007; (2) effective November 2006, includes an additional annual fee of $2.0 million related to the acquisition of our wholesale propane logistics business from DCP Midstream, LLC, subject to the same conditions noted above; (3) effective May 2007, includes an additional annual fee of $0.2 million related to the Southern Oklahoma asset acquisition, subject to the same conditions noted above; (4) effective with our acquisition of Discovery includes an additional annual fee of $0.2 million; (5) effective August 2007, includes an additional annual fee of $0.6 million for general and administrative expenses payable to DCP Midstream, LLC to account for additional services provided to us; and (6) effective with our acquisition of the MEG subsidiaries in August 2007, includes an additional annual fee of $1.6 million.

The Omnibus Agreement addresses the following matters:

•

our obligation to reimburse DCP Midstream, LLC for the payment of operating expenses, including salary and benefits of operating personnel, it incurs on our behalf in connection with our business and operations;

•

our obligation to reimburse DCP Midstream, LLC for providing us with general and administrative services with respect to our business and operations, subject to an increase for 2008 based on increases in the Consumer Price Index and subject to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of the special committee of the General Partner’s board of directors;

•

our obligation to reimburse DCP Midstream, LLC for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage;

•

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

•

DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements were in effect as of the closing of our initial public offering in December 2005, until the earlier to occur of the fifth anniversary of the closing of our initial public offering or such time as we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and

•

DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts.

Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions, will be terminable by DCP Midstream, LLC at its option if the general partner is removed without cause and units held by the general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of us, the general partner (DCP Midstream GP, LP) or the General Partner (DCP Midstream GP, LLC).

Competition

None of DCP Midstream, LLC, nor any of its affiliates, including Spectra Energy and ConocoPhillips, is restricted, under either the partnership agreement or the Omnibus Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Spectra Energy and ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Indemnification

Under the Omnibus Agreement, DCP Midstream, LLC will indemnify us for three years after the closing of our initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of our initial public offering. DCP Midstream, LLC’s maximum liability for this indemnification obligation does not exceed $15.0 million and DCP Midstream, LLC does not have any obligation under this indemnification until our aggregate losses exceed $250,000. DCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of our initial public offering. We have agreed to indemnify DCP Midstream, LLC against environmental liabilities related to our assets to the extent DCP Midstream, LLC is not required to indemnify us.

Additionally, DCP Midstream, LLC will indemnify us for losses attributable to title defects, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify DCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to DCP Midstream, LLC’s indemnification obligations. In addition, DCP Midstream, LLC has agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions required to be made by us to Black Lake Pipe Line Company, or Black Lake, associated with any repairs to the Black Lake pipeline that are determined to be necessary as a result of the currently ongoing pipeline integrity testing occurring from 2005 through 2007. DCP Midstream, LLC had also agreed to indemnify us for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that were determined to be necessary as a result of pipeline integrity testing that occurred in 2006. Pipeline integrity testing and repairs were our responsibility and were recognized as operating and maintenance expense. Reimbursement of these expenses from DCP Midstream, LLC were not significant and were recognized by us as capital contributions.

In connection with our acquisitions of East Texas and Discovery from DCP Midstream, LLC, an affiliate of DCP Midstream, LLC will indemnify us for one year following the closing for the breach of the representations and warranties made under the acquisition agreement and certain environmental matters and tax matters associated with these assets that were identified at the time of closing and that were attributable to periods prior to the closing date. In addition, the same affiliate of DCP Midstream, LLC agreed to indemnify us for one year after closing for the underpayment of trade payables that pertain to periods prior to closing and agreed to indemnify us for two years after closing for any claims for fines or penalties of any governmental authority for periods prior to the closing and that are associated with certain East Texas assets that were formerly owned by Gulf South and UP Fuels. The indemnity obligation for breach of certain representations and warranties is not effective until claims exceed in the aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.

Other Agreements and Transactions with DCP Midstream, LLC

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to the inlet of the Pelico system, and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Because of DCP Midstream, LLC’s ability to move natural gas around Pelico, there are certain contractual relationships around Pelico that define how natural gas is bought and sold between us and DCP Midstream, LLC. The agreement is described below:

•

DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. We generally report purchases associated with these activities gross in the consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates.

•

If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index-based price, less a contractually agreed-to marketing fee. We generally report revenues associated with these activities gross in the consolidated statements of operations as sales of natural gas, propane and NGLs to affiliates.

•

In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC, plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential, plus a fixed fuel charge and other related adjustments. We generally report revenues and purchases associated with these activities net in the consolidated statements of operations as transportation and processing services to affiliates.

In addition, we sell NGLs and condensate from our Minden and Ada processing plants, and condensate from our Pelico system to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for transportation and other charges from the tailgate of the respective asset, which is recorded in the consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates. We also sell propane to a subsidiary of DCP Midstream, LLC.

We also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze pipeline, pursuant to a fee-based rate that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on the Seabreeze pipeline under a 17-year transportation agreement expiring in 2022. We generally report revenues associated with these activities in the consolidated statements of operations as transportation and processing services to affiliates.

In December 2006, we completed construction of our Wilbreeze pipeline, which connects a DCP Midstream, LLC gas processing plant to our Seabreeze pipeline. The project is supported by a 10-year NGL product dedication agreement with DCP Midstream, LLC. We generally report revenues, which are earned pursuant to a fee-based rate applied to the volumes transported on this pipeline, in the consolidated statements of operations as transportation and processing services to affiliates.

We anticipate continuing to purchase commodities from and sell commodities to DCP Midstream, LLC in the ordinary course of business.

In the second quarter of 2006, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for capital projects, which were forecasted to be completed prior to our initial public offering, but were not completed by that date. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $3.4 million during 2006, to reimburse us for the capital costs we incurred, primarily for growth capital projects. At December 31, 2006, all of these projects were completed.

We had an operating lease with an affiliate during the years ended December 31, 2005 and 2004. Operating lease expense related to this lease was $0.7 million and $2.8 million for the years ended December 31, 2005 and 2004, respectively.

DCP Midstream, LLC was a significant customer during the six months ended June 30, 2007 and 2006 (unaudited), and during the years ended December 31, 2006, 2005 and 2004.

Duke Energy

Prior to December 31, 2006, we charged transportation fees, sold a portion of our residue gas to, and purchased raw natural gas from, Duke Energy Corporation, or Duke Energy, and its affiliates.

ConocoPhillips

We have multiple agreements whereby we provide a variety of services to ConocoPhillips and its affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing arrangements, gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We

received $1.5 million (unaudited), $1.2 million (unaudited), $3.9 million, $0.2 million and $0.3 million of capital reimbursements during the six months ended June 30, 2007 and 2006 and the years ended December 31, 2006, 2005 and 2004, respectively.

The following table summarizes the transactions with DCP Midstream, LLC, Duke Energy and ConocoPhillips as described above ($ in millions):


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006		2005			2004
	(unaudited)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	113.9		$	120.9		$	231.7	$	108.8		$	71.6
Transportation and processing services	$	2.9		$	2.5		$	4.8	$	0.3		$	0.6
Purchases of natural gas, propane and NGLs	$	70.0		$	48.0		$	102.9	$	134.4		$	94.4
(Losses) gains from non-trading derivative activity	$	(0.5	)	$	(0.5	)	$	0.1	$	(0.9	)	$	(1.9	)
General and administrative expense	$	4.7		$	3.8		$	8.1	$	9.1		$	7.8
Duke Energy:
Sales of natural gas, propane, NGLs and condensate	$	—		$	—		$	—	$	1.4		$	10.3
Transportation and processing services	$	—		$	—		$	—	$	0.3		$	0.5
Purchases of natural gas, propane and NGLs	$	—		$	1.9		$	3.4	$	4.7		$	3.4
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	2.7		$	0.1		$	1.1	$	7.3		$	3.7
Transportation and processing services	$	5.0		$	3.5		$	8.0	$	10.0		$	9.9
Purchases of natural gas, propane and NGLs	$	13.5		$	5.7		$	12.9	$	18.7		$	18.6

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


	June 30, 2007		December 31,
	June 30, 2007		2006		2005
	(unaudited)
DCP Midstream, LLC:
Accounts receivable	$	19.9	$	30.0	$	53.5
Accounts payable	$	19.5	$	46.6	$	15.9
Spectra Energy:
Accounts receivable	$	0.3	$	—	$	—
Duke Energy:
Accounts receivable	$	—	$	0.2	$	0.4
Accounts payable	$	—	$	1.8	$	24.0
ConocoPhillips:
Accounts receivable	$	10.2	$	4.6	$	2.6
Accounts payable	$	2.1	$	2.0	$	2.5

6. Property, Plant and Equipment

A summary of property, plant and equipment by classification 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	$	286.3		$	107.3		$	95.9
Processing plants	25 — 30 Years		53.2			53.2			53.4
Terminals	25 — 30 Years		9.2			8.2			8.2
Transportation	25 — 30 Years		139.4			139.6			127.4
General plant	3 — 5 Years		2.7			3.6			3.6
Construction work in progress			20.9			16.2			11.4

Property, plant and equipment			511.7			328.1			299.9
Accumulated depreciation			(141.0	)		(133.4	)		(121.2	)

Property, plant and equipment, net		$	370.7		$	194.7		$	178.7

Depreciation expense was $7.6 million (unaudited) and $6.1 million (unaudited) for the six months ended June 30, 2007 and 2006, respectively, and $12.4 million, $12.0 million and $13.1 million for the years ended December 31, 2006, 2005 and 2004, respectively.

In addition, property, plant and equipment includes $0.9 million (unaudited) and $1.0 million (unaudited), and $1.4 million, $1.1 million and $0.1 million of non-cash additions for the six months ended June 30, 2007 and 2006, and for the years ended December 31, 2006, 2005 and 2004, respectively.

Asset Retirement Obligations — Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, was $1.1 million (unaudited), $0.5 million and $0.3 million at June 30, 2007, and December 31, 2006 and 2005, respectively. Accretion expense for the six months ended June 30, 2007 and 2006 (unaudited), and for the years ended December 31, 2006, 2005 and 2004 was not significant.

7. Goodwill and Intangible Assets

Goodwill consists of the amount that was recognized by DCP Midstream, LLC when it acquired certain assets which are now included in our Wholesale Propane Logistics segment, and was allocated based on fair value to the wholesale propane logistics business in order to present historical information about the assets we acquired in November 2006. As this was a transaction among entities under common control, our financial information includes the results of our wholesale propane logistics business for all periods presented. There were no changes in the $29.3 million carrying amount of goodwill during the six months ended June 30, 2007 (unaudited) or the years ended December 31, 2006 or 2005. We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment test indicated that our reporting unit’s fair value exceeded its carrying or book value; therefore, we have determined that there is no indication of impairment.

Intangible assets consist primarily of commodity purchase contracts. The gross carrying amount and accumulated amortization for the commodity purchase contracts and other intangible assets are included in the accompanying consolidated balance sheets as intangible assets, and are as follows ($ in millions):


	June 30, 2007			December 31,
	June 30, 2007			2006			2005
	(unaudited)
Gross carrying amount	$	16.9		$	4.4		$	11.0
Accumulated amortization		(1.9	)		(1.6	)		(7.8	)

Intangible assets, net	$	15.0		$	2.8		$	3.2

Intangible assets increased in May 2007 as a result of the Southern Oklahoma asset acquisition, through which $12.5 million of net commodity purchase contracts were acquired. These intangible assets have a life of 15 years and are being amortized through 2022.

One customer has notified us that they intend to exercise their early termination right prior to the end of the contract term. Accordingly, we are not amortizing the estimated termination fee of $0.5 million, which is included in the $15.0 million of intangible assets, net in the above table.

For the six months ended June 30, 2007 and 2006, we recorded amortization expense associated with these intangibles of $0.3 million (unaudited) for both periods, and for each of the years ended December 31, 2006, 2005 and 2004, we recorded amortization expense associated with these intangibles of $0.4 million, $0.7 million, and $1.6 million, respectively. As of June 30, 2007 (unaudited), the remaining amortization periods for these contracts range from approximately two to 20 years, with a weighted-average remaining period of approximately 15 years.

Estimated future amortization for these contracts is as follows ($ in millions):


	(unaudited)
Remainder of 2007	$	0.6
2008		1.1
2009		0.9
2010		0.9


	(unaudited)
2011		0.9
Thereafter		10.1

Total	$	14.5

8. Equity Method Investments

We have four investments accounted for using the equity method. The following table includes our percentage of ownership and the carrying value of our investments as of the indicated dates ($ in millions):


	Percentage of Ownership as of June 30, 2007, and December 31, 2006 and 2005		Carrying Value as of
			June 30, 2007		December 31,
			June 30, 2007		2006		2005
			(unaudited)
Discovery Producer Services LLC	40	%	$	110.6	$	113.4	$	101.8
DCP East Texas Holdings, LLC	25	%		51.4		50.9		48.4
Black Lake Pipe Line Company	45	%		6.2		5.7		5.3
Other	50	%		0.2		0.2		0.2

Total equity method investments			$	168.4	$	170.2	$	155.7

Discovery operates a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32,000 Bbl/d natural gas liquids fractionator plant near Paradis, Louisiana, a natural gas pipeline from offshore deep water in the Gulf of Mexico that transports gas to our processing plant in Larose, Louisiana with a design capacity of 600 MMcf/d and approximately 173 miles of pipe, and several laterals expanding their presence in the Gulf. There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $46.1 million (unaudited), $48.6 million and $53.5 million at June 30, 2007, and December 31, 2006 and 2005, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

East Texas is engaged in the business of gathering, transporting, treating, compressing, processing, and fractionating natural gas and natural gas liquids, or NGLs. Their 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 their 845 mile gathering system, as well as third party gathering systems. The complex is adjacent to their 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.

Black Lake owns a 317-mile NGL pipeline, with a throughput capacity of approximately 40 MBbls/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $6.5 million (unaudited), $6.7 million and $7.0 million at June 30, 2007, and December 31, 2006 and 2005, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

Prior to December 7, 2005, DCP Midstream Partners Predecessor held a 50% interest in Black Lake. Upon completion of our initial public offering, DCP Midstream, LLC retained a 5% interest in Black Lake.

Earnings from equity method investments for the six months ended June 30, 2007 and 2006, and for the years ended December 31, 2006, 2005 and 2004, were as follows ($ in millions):


	Six Months Ended June 30,					Year Ended December 31,
	2007			2006		2006		2005			2004
	(unaudited)
Discovery Producer Services LLC	$	7.6		$	8.6	$	16.9	$	10.8		$	7.8
DCP East Texas Holdings, LLC		4.7			7.1		12.0		14.5			9.2
Black Lake Pipe Line Company and other		0.5			0.1		0.3		0.4			0.6

Total earnings from equity method investments	$	12.8		$	15.8	$	29.2	$	25.7		$	17.6

Distributions from equity method investments	$	18.5		$	11.1	$	25.9	$	36.7		$	13.4

Earnings from equity method investments, net of distributions	$	(5.7	)	$	4.7	$	3.3	$	(11.0	)	$	4.2

The following summarizes financial information of our equity method investments (unaudited) ($ in millions):


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
Statements of operations:
Operating revenue	$	323.2		$	365.4		$	686.9		$	672.1		$	489.6
Operating expenses	$	(291.3	)	$	(323.1	)	$	(612.2	)	$	(594.8	)	$	(440.7	)
Net income	$	32.6		$	43.1		$	77.4		$	77.9		$	49.5


	June 30, 2007		December 31,
	June 30, 2007		2006		2005
Balance sheet:
Current assets	$	82.9	$	108.9	$	106.7
Non-current assets		634.5		630.7		634.3
Current liabilities		88.8		94.8		109.7
Non-current liabilities		6.6		6.0		1.8

Net assets	$	622.0	$	638.8	$	629.5

9. Impairment of Equity Method Investment

In the third quarter of 2004, we recognized an other-than-temporary impairment of our investment in Black Lake totaling $4.4 million as impairment of equity method investment, included in the consolidated statements of operations. This investment was written down to fair value, which was determined based on management’s best estimates of discounted future cash flow models. The charge associated with this impairment is recorded in the NGL Logistics segment.

10. Estimated Fair Value of Financial Instruments

We have determined the following fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The following summarizes the estimated fair value of financial instruments ($ in millions):


	June 30, 2007						December 31, 2006				December 31, 2005
	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(unaudited)
Restricted investments	$	—		$	—		$	102.0	$	102.0	$	100.4	$	100.4
Accounts receivable	$	70.6		$	70.6		$	78.2	$	78.2	$	122.2	$	122.2
Accounts payable	$	92.3		$	92.3		$	117.3	$	117.3	$	138.3	$	138.3
Unrealized (losses) gains on non-trading derivative and hedging instruments	$	(15.2	)	$	(15.2	)	$	7.3	$	7.3	$	0.4	$	0.4
Long-term debt	$	249.0		$	249.0		$	268.0	$	268.0	$	210.1	$	210.1

The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.

The carrying value of long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

11. Debt

Long-term debt was as follows ($ in millions):


	Principal Amount
	June 30, 2007		December 31,
	June 30, 2007		2006		2005
	(unaudited)
Revolving credit facility, weighed-average interest rate of 5.77% at June 30, 2007, due June 21, 2012	$	249.0	$	168.0	$	110.0
Term loan facility, interest rate of 5.47% at December 31, 2006, due December 7, 2010		—		100.0		100.1

Total long-term debt	$	249.0	$	268.0	$	210.1

Credit Agreements

On June 21, 2007, we entered into the Amended and Restated Credit Agreement, or the Amended Credit Agreement, that replaced our existing credit agreement, or the Credit Agreement, which consists of:

•

a $600.0 million revolving credit facility; and

•

a $250.0 million term loan facility.

At June 30, 2007 (unaudited) and December 31, 2006, we had $0.2 million of letters of credit outstanding. There were no letters of credit outstanding at December 31, 2005. Outstanding balances under the term loan facility are fully collateralized by investments in high-grade securities, which are classified as restricted investments in the accompanying consolidated balance sheet as of December 31, 2006. In June 2007, we incurred $0.5 million (unaudited) of debt issuance costs associated with the Amended Credit Agreement. In December 2005, we incurred $0.7 million of debt issuance costs associated with the Credit Agreement. These expenses are deferred as other non-current assets in the consolidated balance sheet and will be amortized over the term of the Credit Agreement.

As of June 30, 2007, and December 31, 2006 and 2005, $0.4 million (unaudited), $1.1 million and $0.8 million, respectively, was recorded as accrued interest payable in the consolidated balance sheets. We paid $10.0 million (unaudited) in interest and facility fees, net of capitalized interest of $0.2 million (unaudited), during the six months ended June 30, 2007. We paid $11.1 million in interest and facility fees, net of capitalized interest of $0.4 million, in 2006. We paid $0.5 million of facility fees during 2005.

Under the Amended Credit Agreement, indebtedness under the revolving credit facility bears interest at either: (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50%; or (2) LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our leverage level or credit rating. As of June 30, 2007, the weighted-average interest rate on our revolving credit facility was 5.77% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to either: (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50%.

The Amended Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended Credit Agreement) of not more than 5.75 to 1.0 through and including the quarter ended June 30, 2007 and 5.0 to 1.0 thereafter, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.50 to 1.0. The Amended Credit Agreement also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as is defined by the Amended Credit Agreement) of equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination.

Bridge Loan

In May 2007, we entered into a two-month bridge loan, or the Bridge Loan, which provided for borrowings up to $100.0 million, and had terms and conditions substantially similar to those of our Credit Agreement. In conjunction with our entering into the Bridge Loan, our Credit Agreement was amended to provide for additional unsecured indebtedness, of an amount not to exceed $100.0 million, which was due and payable no later than August 9, 2007.

We used borrowings on the Bridge Loan of $88.0 million to partially fund the Southern Oklahoma asset acquisition. The remaining $12.0 million available for borrowing on the Bridge Loan was not utilized. We used a portion of the net proceeds of a private placement of limited partner units to extinguish the $88.0 million outstanding on the Bridge Loan.

Guarantor Financial Information

In April 2007, we filed with the SEC a universal shelf registration statement on Form S-3 with a maximum aggregate offering price of $1.5 billion, which will, upon effectiveness, allow us to register and issue additional partnership units and debt obligations. In connection with the universal shelf registration statement, all of our subsidiaries, or Guarantors, have fully and unconditionally guaranteed, on a joint and several basis, any debt obligations we may register. DCP Midstream Partners, LP, the parent company of the Guarantors and the co-issuer of the debt obligations with its wholly-owned finance subsidiary, DCP Midstream Partners Finance Corp., has no independent assets or operations. There are no significant restrictions on DCP Midstream Partners, LP’s ability to obtain funds from its subsidiaries by dividend or loan.

12. Partnership Equity and Distributions

General — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (defined below) to unitholders of record on the applicable record date, as determined by our general partner.

On June 22, 2007, we entered into a private placement agreement, or the Private Placement Agreement, with a group of institutional investors for $130.0 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $128.5 million, net of offering costs. In connection with the Private Placement Agreement, we entered into a registration rights agreement with institutional investors that requires us to file a shelf registration statement with the Securities and Exchange Commission, or SEC, to register the units by the earlier of within 120 days of the close of the private placement or when a shelf registration statement is filed to register the units to be issued and sold by us under a common unit purchase agreement, which is contingent on the closing of the MEG acquisition. In addition the registration rights agreement requires us to use our commercially reasonable efforts to cause the registration statement to become effective within 210 days of the closing of the private placement, or we will be liable to the institutional investors for liquidated damages of 0.25% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period for the first 60 days following the 210^th day, increasing by an additional 0.25% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period.

Definition of Available Cash — Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

•

less the amount of cash reserves established by the general partner to:

•

provide for the proper conduct of our business;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;

•

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights — Prior to June 22, 2007, the general partner was entitled to 2% of all quarterly distributions that we make prior to our liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its general partner interest. The general partner’s 2% interest in these distributions was reduced to 1.7% on June 22, 2007 as a result of the issuance of the 3,005,780 common limited partner units in conjunction with the Private Placement Agreement.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The general partner’s incentive distribution rights were not reduced as a result of the Private Placement Agreement, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its general partner interest. Please read the Distributions of Available Cash during the Subordination Period and Distributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Class C Units — The Class C units have the same liquidation preference, rights to cash distributions and voting rights as the common units. On July 2, 2007, the Class C units were converted to common units.

Subordinated Units — All of the subordinated units are held by DCP Midstream, LLC. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period,

the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The subordination period has an early termination provision that permits 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2008 and the other 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2009, provided the tests for ending the subordination period contained in the partnership agreement are satisfied. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.

Treasury Units (unaudited) — In March 2007, we purchased 4,000 units on the open market, at an average cost of $39.16 per unit. These units were held as treasury units at June 30, 2007, and will be used for director compensation pursuant to the DCP Midstream Partners, LP Long-Term Incentive Plan, or LTIP. In August 2007, these units were issued to our general partner.

Distributions of Available Cash during the Subordination Period — Our partnership agreement, after adjustment for the general partner’s relative ownership level, currently 1.7%, requires that we make distributions of Available Cash for any quarter during the subordination period in the following manner:

•

first, to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;

•

second, to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;

•

third, to the subordinated unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;

•

fourth, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter (the First Target Distribution);

•

fifth, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter (the Second Target Distribution);

•

sixth, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter (the Third Target Distribution); and

•

thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders (the Fourth Target Distribution).

Distributions of Available Cash after the Subordination Period — Our partnership agreement after adjustment for the general partner’s relative ownership level requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;

•

second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;

•

third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and

•

thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2007 and 2006 ($ in millions, except per unit distribution amounts):


Payment Date	Per Unit Distribution		Total Cash Distribution
May 15, 2007	$	0.465	$	8.6
February 14, 2007		0.430		7.8
November 14, 2006		0.405		7.4
August 14, 2006		0.380		6.7
May 15, 2006		0.350		6.3
February 13, 2006 (a)		0.095		1.7

(a)	Represents the pro rata portion of our Minimum Quarterly distribution of $0.35 per unit for the period December 7, 2005, the closing of our initial public offering, through December 31, 2005.

13. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

The impact of our derivative activity on our results of operations and financial position is summarized below ($ in millions):


	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
	(unaudited)
Commodity cash flow hedges:
Losses due to ineffectiveness	$	—		$	(0.5	)	$	(0.3	)	$	0.3		$	—
Gains reclassified into earnings as a result of settlements	$	1.8		$	0.7		$	2.6		$	—		$	—
Commodity non-trading derivative activity:
(Losses) gains from non-trading derivative activity	$	(15.0	)	$	(0.5	)	$	0.1		$	(0.9	)	$	(1.9	)
Interest rate cash flow hedges:
Gains reclassified into earnings as a result of settlements	$	0.3		$	—		$	0.1		$	—		$	—


	June 30, 2007			December 31,
	June 30, 2007			2006		2005		2004
	(unaudited)
Commodity cash flow hedges:
Net deferred (losses) gains in AOCI	$	(2.0	)	$	6.9	$	0.4	$	—
Interest rate cash flow hedges:
Net deferred gains in AOCI	$	1.5		$	0.4	$	—	$	—

For the six months ended June 30, 2007 and 2006 (unaudited), and the year ended December 31, 2006, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring, or due to a derivative no longer qualifying as an effective hedge.

We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate the effects of the identified risks. In general, we attempt to mitigate risks related to the variability of future cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. We have established a comprehensive risk management policy, or the Risk Management Policy, and a risk management committee, to monitor and manage market risks associated with commodity prices and interest rates. Our Risk Management Policy prohibits the use of derivative instruments for speculative purposes.

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

Interest Rate Risk — Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Credit Risk — In the Natural Gas Services segment, we sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. In the Wholesale Propane Logistics segment, we sell primarily to retail propane distributors. In the NGL Logistics segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream, LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with DCP

Midstream, LLC’s credit policy and guidelines. The agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a satisfactory form.

Commodity Cash Flow Hedges — We executed a series of derivative financial transactions, referred to as swap contracts. As a result of these transactions, we have mitigated a significant portion of our expected natural gas and NGL commodity price risk through 2011 relating to our percentage-of-proceeds gathering and processing contracts and of our expected condensate commodity price risk relating to condensate recovered from gathering operations.

We use natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is accumulated in AOCI, and the ineffective portion is recorded in the consolidated statements of operations as sales of natural gas, propane, NGLs and condensate. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction will be reclassified to the consolidated statements of operations in the same accounts as the item being hedged. As of June 30, 2007, $0.2 million (unaudited) of deferred net gains on derivative instruments in AOCI will be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Commodity Fair Value Hedges — We use fair value hedges to mitigate risk to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) to reduce our exposure to fixed price risk by swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index-based).

For the six months ended June 30, 2007 and 2006 (unaudited), and for the years ended December 31, 2006, 2005 and 2004, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. During the six months ended June 30, 2007 and 2006 (unaudited) and during the years ended December 31, 2006, 2005 and 2004, there were no firm commitments that no longer qualified as fair value hedge items and, therefore, we did not recognize an associated gain or loss.

Normal Purchases and Normal Sales — If a contract qualifies and is designated as a normal purchase or normal sale, no recognition of the contract’s fair value in the consolidated financial statements is required until the associated delivery period impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of physical natural gas, propane or NGLs in future periods.

Commodity Non-Trading Derivative Activity — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in price variability across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.

Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings. We manage our asset-based activities in accordance with our risk management policy, which limits exposure to market risk and requires regular reporting to management of potential financial exposure. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.

In May 2007, we executed a series of financial derivatives to mitigate a portion of the commodity price exposure associated with the Southern Oklahoma asset acquisition. We entered into natural gas swap contracts for 1,500 MMBtu/d at $7.54 per MMBtu and into crude oil swap contracts for 650 Bbls/d at $67.60 per Bbl for a term from June 2007 through December 2013. In June 2007, we executed a series of financial derivatives to mitigate a portion of the commodity price exposure associated with our Northern Louisiana system assets. We entered into crude oil swap contracts for 250 Bbls/d at $71.35/Bbl for 2011, 600 Bbls/d at $71.00/Bbl for 2012 and 600 Bbls/d at $71.20/Bbl for 2013. In March 2007, DCP Midstream, LLC entered into a crude oil swap, or the 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 at $66.72 per barrel. We acquired the Swap from DCP Midstream, LLC in July 2007. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.

Interest Rate Cash Flow Hedges — During 2006, we entered into interest rate swap agreements to hedge the variable interest rate on $125.0 million of the indebtedness outstanding under our revolving credit facility. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation.

The effective portions of changes in fair value are recognized in AOCI in the consolidated balance sheets. As of June 30, 2007, $0.4 million (unaudited) of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Ineffective portions of changes in fair value are recognized in earnings. The agreements reprice prospectively approximately every 90 days, and expire on December 7, 2010. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 4.68% to 5.08%, and receive interest payments based on the three-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of the agreements.

14. Equity-Based Compensation

Total compensation cost for equity-based arrangements was as follows ($ in millions):


	Six Months Ended June 30,				Year Ended December 31,
	2007		2006		2006		2005		2004
	(unaudited)
Performance Units	$	0.5	$	0.1	$	0.2	$	—	$	—
Phantom Units		0.4		0.2		0.4		—		—

Total compensation cost	$	0.9	$	0.3	$	0.6	$	—	$	—

On November 28, 2005, the board of directors of our General Partner adopted the LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us, effective as of December 7, 2005. Under the LTIP, equity-based instruments may be granted to our key employees. The LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of DERs. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the LTIP. Awards that are canceled, forfeited or are withheld to satisfy the General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the General Partner’s board of directors. We first granted awards under the LTIP during 2006.

Performance Units — We have awarded phantom LPUs, or Performance Units, pursuant to the LTIP to certain employees. Performance Units generally vest in their entirety at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over three year performance periods. The final performance payout is determined by the compensation committee of the board of directors of the General Partner. Each Performance Unit includes a DER, which will be paid in cash at the end of the performance period.

At June 30, 2007, there was approximately $1.8 million (unaudited) of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of 2.1 years. The following table presents information related to the Performance Units:


	Units (a)		Grant Date Weighted- Average Price per Unit		Measurement Date Weighted- Average Price per Unit
Outstanding at December 31, 2005	—		$	—
Granted	40,560		$	26.96
Forfeited	(17,470	)	$	26.96

Outstanding at December 31, 2006	23,090		$	26.96
Granted	29,610		$	37.23

Outstanding at June 30, 2007 (unaudited)	52,700		$	32.73	$	46.62

Expected to vest (unaudited)	52,700		$	32.73	$	46.62

The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.

Phantom Units — In conjunction with our initial public offering, in January 2006 the General Partner’s board of directors awarded phantom LPUs, or Phantom Units, to key employees, and to directors who are not officers or employees of affiliates of the General Partner. Of these Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date, and 5,332 units vest ratably over two years. Each Phantom Unit includes a DER, which is paid quarterly in arrears.

In May 2007, we granted 4,000 Phantom Units under the LTIP to directors who are not officers or employees of affiliates of the General Partner as part of their annual director fees for 2007. These Phantom Units will fully vest six months following the grant date. Each Phantom Unit includes a DER, which is paid quarterly in arrears.

At June 30, 2007, there was approximately $0.6 million (unaudited) of unrecognized compensation expense related to the Phantom Units that is expected to be recognized over a weighted-average period of 1.1 years. The following table presents information related to the Phantom Units:


	Units		Grant Date Weighted- Average Price per Unit		Measurement Date Weighted- Average Price per Unit
Outstanding at December 31, 2005	—		$	—
Granted	35,900		$	24.05
Forfeited	(11,200	)	$	24.05

Outstanding at December 31, 2006	24,700		$	24.05
Granted	4,000		$	42.69
Forfeited	(2,668	)	$	24.05

Outstanding at June 30, 2007 (unaudited)	26,032		$	26.91	$	46.62

Expected to vest (unaudited)	26,032		$	26.91	$	46.62

The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.

We intend to settle the awards issued under the LTIP in cash upon vesting, with the exception of the units granted in May 2007. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of our common units at each measurement date. During the six months ended June 30, 2007, 2,668 awards vested and were settled in cash for $0.1 million (unaudited). No awards were vested or settled during the six months ended June 30, 2006 or the year ended December 31, 2006.

15. Income Taxes

We are structured as a master limited partnership, which is a pass-through entity for U.S. income tax purposes. The income tax expense reflected on our consolidated statements of operations is applicable to our wholesale propane logistics business. On

December 7, 2005, our wholesale propane logistics business changed its tax structure, which resulted in its activities changing from taxable to non-taxable for United States income tax purposes.

Income tax expense consisted of the following for the years ended December 31, 2005 and 2004 ($ in millions):


	Year Ended December 31,
	2005			2004
Current:
Federal	$	3.0		$	2.0
State		0.8			0.6
Deferred:
Federal		(0.4	)		(0.1	)
State		(0.1	)		—

Total income tax expense	$	3.3		$	2.5

A reconciliation of the actual income tax expense and the amount computed by applying the federal statutory rate of 35% to the income before income taxes is as follows ($ in millions):


	Year Ended December 31,
	2005			2004
Federal income tax at statutory rate	$	3.4		$	2.1
State income taxes, net of federal benefit		0.6			0.5
Change in tax structure		(0.5	)		—
Depreciation and amortization		—			0.4
Net trading margins		—			(0.4	)
Other		(0.2	)		(0.1	)

Total income tax expense	$	3.3		$	2.5

The change in tax structure resulted in the reversal of the net deferred tax liabilities in the year ended December 31, 2005. Accordingly, we had no deferred tax balances as of June 30, 2007 (unaudited), December 31, 2006 or 2005, and no income tax expense for the six months ended June 30, 2007 or 2006 (unaudited), or the year ended December 31, 2006.

In May 2006, the State of Texas enacted a new margin-based franchise tax into 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, which is assessed at 1% of taxable margin apportioned to Texas, will be based on the margin earned during the prior calendar year.

The Texas margin tax is considered an income tax for purposes of calculating the deferred tax liability. GAAP requires that deferred taxes be adjusted upon enactment of new tax law, which occurred in 2006. The deferred tax liabilities associated with the Texas margin tax were insignificant.

16. 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 the First Target Distribution Level, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of Available Cash and not earnings. In periods in which our aggregate net income does not exceed the First Target Distribution Level, there is no impact on our calculation of earnings per limited partner unit. During the six months ended June 30, 2007 (unaudited), our aggregate net income per LPU exceeded the Third Target

Distribution level, and as a result we allocated $1.8 million in additional earnings to the general partner. During the six months ended June 30, 2006 (unaudited), our aggregate net income per LPU was less than the First Target Distribution level, and as a result there was no impact on our calculation of earnings per LPU. During the year ended December 31, 2006, our aggregate net income per limited partner unit exceeded the Second Target Distribution level, and as a result we allocated $1.3 million in additional earnings to the general partner.

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions, by the weighted-average number of outstanding limited partner units during the period.

The following table illustrates our calculation of net income per limited partner unit ($ in millions):


	Six Months Ended June 30,						Year ended December 31,
	2007			2006			2006			2005
	(unaudited)
Net income	$	16.6		$	32.0		$	61.9		$	69.8
Less:
Net income attributable to predecessor operations		(3.6	)		(17.8	)		(26.6	)		(65.1	)

Net income attributable to the partnership		13.0			14.2			35.3			4.7
Less: General partner interest in net income		(0.6	)		(0.3	)		(0.7	)		(0.1	)

Limited partners’ interest in net income		12.4			13.9			34.6			4.6
Less: Additional earnings allocation to general partner		(1.8	)		—			(1.3	)		(1.1	)

Net income available to limited partners	$	10.6		$	13.9		$	33.3		$	3.5

Net income per limited partner unit — basic and diluted	$	0.60		$	0.79		$	1.90		$	0.20

17. Commitments and Contingent Liabilities

Litigation

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation stems from an ongoing commercial dispute involving the construction of our Wilbreeze pipeline, which was completed in December 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. Driver claims damages in the amount of $2.4 million for breach of contract. We believe Driver’s position in this litigation is without merit and we intend to vigorously defend ourselves against this claim. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.

El Paso — In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of our general partner, DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which is prior to our ownership of this asset. El Paso claims damages, including interest, in the amount of $5.7 million in the litigation, the bulk of which stems from audit claims under our commercial contract for historical periods prior to our ownership of this asset. We will only be responsible for potential payments, if any, for claims that involve periods of time after the date we acquired this asset from DCP Midstream, LLC in December 2005. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Seabreeze — In June 2006, a DCP Midstream, LLC customer whose plant is served by our Seabreeze pipeline notified DCP Midstream, LLC that off specification NGLs had been received into their facility. Our Seabreeze pipeline transports NGLs owned by DCP Midstream, LLC that are delivered to the customer under the terms of a transportation agreement. The customer sent a letter to DCP Midstream, LLC claiming that the off specification NGLs delivered to their facility caused damage to their plant facility. On December 29, 2006 we entered into a settlement agreement with the customer to settle all our issues regarding this matter, and our portion of the settlement was $0.3 million.

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

Insurance — In 2005, DCP Midstream, LLC carried insurance coverage, which included our assets and operations, with an affiliate of Duke Energy. Beginning in 2006, DCP Midstream, LLC elected to carry our property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips. DCP Midstream, LLC provides our remaining insurance coverage with a third party insurer. DCP Midstream, LLC’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; (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; and (6) directors and officers insurance covering our directors and officers for acts related to our activities. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations. Effective August 2006, we contracted with a third party insurer for our property and primary liability insurance coverage.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Indemnification — DCP Midstream, LLC has indemnified us for three years after the closing of our initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing of our initial public offering. See the “Indemnification” section of Note 5 for additional details.

Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, amounted to $5.8 million (unaudited), $5.5 million (unaudited), $11.2 million, $10.3 million, and $1.5 million for the six months ended June 30, 2007 and 2006, and for the years ended December 31, 2006, 2005 and 2004, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at June 30, 2007 ($ in millions):


	(unaudited)
Remainder of 2007	$	4.8
2008		8.4
2009		6.5
2010		5.8
2011		4.8
Thereafter		10.7

Total minimum rental payments	$	41.0

18. Business Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.

Natural Gas Services — The Natural Gas Services segment consists of the Northern Louisiana system assets, an integrated gas gathering, compression, treating, processing, and transportation system located in northern Louisiana, as well as the Southern Oklahoma system that was acquired in May 2007. The Natural Gas Services segment also consists of our 25% limited liability company interest in East Texas, our 40% limited liability company interest in Discovery, and the Swap acquired in July 2007.

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of six owned propane rail terminals located in the Midwest and northeastern United States, one leased propane marine terminal located in Providence, Rhode Island, one propane pipeline terminal in Midland, Pennsylvania and access to several open access pipeline terminals.

NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, which are located along the Gulf Coast area of southeastern Texas, and a non-operated 45% equity interest in the Black Lake interstate NGL pipeline located in northern Louisiana and southeastern Texas. The Wilbreeze transportation pipeline was not operational until December 2006. Our equity interest consists of 45% from December 7, 2005 through December 31, 2006, and 50% in 2004 and the period from January 1, 2005 through December 6, 2005. DCP Midstream, LLC owns a 5% interest in Black Lake, effective with the date of our initial public offering, and an affiliate of BP PLC owns the remaining interest and is the operator of Black Lake.

These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment. The following tables set forth our segment information ($ in millions):

Six Months Ended June 30, 2007 (unaudited)


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other(c)			Total
Total operating revenue	$	187.7		$	227.0		$	3.6		$	—		$	418.3

Gross margin (a)	$	25.3		$	14.6		$	2.3		$	—		$	42.2
Operating and maintenance expense		(7.2	)		(5.3	)		(0.4	)		—			(12.9	)
Depreciation and amortization expense		(6.7	)		(0.4	)		(0.8	)		—			(7.9	)
General and administrative expense		—			—			—			(11.7	)		(11.7	)
Earnings from equity method investments		12.3			—			0.5			—			12.8
Interest income		—			—			—			2.5			2.5
Interest expense		—			—			—			(8.4	)		(8.4	)

Net income (loss)	$	23.7		$	8.9		$	1.6		$	(17.6	)	$	16.6

Capital expenditures	$	4.1		$	2.6		$	0.9		$	—		$	7.6

Six Months Ended June 30, 2006 (unaudited)


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other(c)			Total
Total operating revenues	$	212.4		$	210.5		$	2.6		$	—		$	425.5

Gross margin (a)	$	35.2		$	8.4		$	2.0		$	—		$	45.6
Operating and maintenance expense		(7.0	)		(4.2	)		(0.3	)		—			(11.5	)
Depreciation and amortization expense		(5.5	)		(0.5	)		(0.4	)		—			(6.4	)
General and administrative expense		—			—			—			(9.3	)		(9.3	)
Earnings from equity method investments		15.7			—			0.1			—			15.8
Interest income		—			—			—			3.0			3.0
Interest expense		—			—			—			(5.2	)		(5.2	)

Net income (loss)	$	38.4		$	3.7		$	1.4		$	(11.5	)	$	32.0

Capital expenditures	$	5.9		$	5.2		$	1.0		$	—		$	12.1

Year ended December 31, 2006:


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other(c)			Total
Total operating revenue	$	415.3		$	375.2		$	5.3		$	—		$	795.8

Gross margin (a)	$	75.3		$	16.0		$	4.1		$	—		$	95.4
Operating and maintenance expense		(13.5	)		(8.6	)		(1.6	)		—			(23.7	)
Depreciation and amortization expense		(11.1	)		(0.8	)		(0.9	)		—			(12.8	)
General and administrative expense		—			—			—			(12.9	)		(12.9	)
General and administrative expense — affiliate		—			—			—			(8.1	)		(8.1	)
Earnings from equity method investments		28.9			—			0.3			—			29.2
Interest income		—			—			—			6.3			6.3
Interest expense		—			—			—			(11.5	)		(11.5	)

Net income (loss)	$	79.6		$	6.6		$	1.9		$	(26.2	)	$	61.9

Capital expenditures	$	6.5		$	9.4		$	11.3		$	—		$	27.2

Year ended December 31, 2005:


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other(c)			Total
Total operating revenues	$	592.8		$	359.8		$	191.7		$	—		$	1,144.3

Gross margin (a)	$	71.4		$	21.8		$	3.8		$	—		$	97.0
Operating and maintenance expense		(14.0	)		(8.2	)		(0.2	)		—			(22.4	)
Depreciation and amortization expense		(10.8	)		(1.0	)		(0.9	)		—			(12.7	)
General and administrative expense		—			—			—			(5.1	)		(5.1	)
General and administrative expense — affiliate		—			—			—			(9.1	)		(9.1	)
Earnings from equity method investments		25.3			—			0.4			—			25.7
Interest income		—			—			—			0.5			0.5
Interest expense		—			—			—			(0.8	)		(0.8	)
Income tax expense (b)		—			—			—			(3.3	)		(3.3	)

Net income (loss)	$	71.9		$	12.6		$	3.1		$	(17.8	)	$	69.8

Capital expenditures	$	7.9		$	2.9		$	—		$	—		$	10.8

Year ended December 31, 2004:


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other(c)			Total
Total operating revenues	$	353.3		$	324.5		$	156.2		$	—		$	834.0

Gross margin (a)	$	53.6		$	16.5		$	3.3		$	—		$	73.4
Operating and maintenance expense		(13.4	)		(6.2	)		(0.2	)		—			(19.8	)
Depreciation and amortization expense		(11.7	)		(2.1	)		(0.9	)		—			(14.7	)
General and administrative expense		—			—			—			(0.9	)		(0.9	)
General and administrative expense — affiliate		—			—			—			(7.8	)		(7.8	)
Earnings from equity method investments		17.0			—			0.6			—			17.6
Impairment of equity method investment		—			—			(4.4	)		—			(4.4	)
Income tax expense (b)		—			—			—			(2.5	)		(2.5	)

Net income (loss)	$	45.5		$	8.2		$	(1.6	)	$	(11.2	)	$	40.9

Capital expenditures	$	2.8		$	0.2		$	0.3		$	—		$	3.3

The following table sets forth our total assets segment information ($ in millions):


	June 30, 2007		December 31,
	June 30, 2007		2006		2005
	(unaudited)
Segment non-current assets:
Natural Gas Services (d)	$	496.5	$	311.7	$	303.0
Wholesale Propane Logistics		51.8		50.2		40.4
NGL Logistics		35.4		35.1		23.5
Other (e)		6.0		109.3		106.8

Total non-current assets		589.7		506.3		473.7
Current assets		159.3		159.6		206.4

Total assets	$	749.0	$	665.9	$	680.1

(a)

Gross margin consists of total operating revenues less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)	Income tax expense relates to our wholesale propane logistics business, which changed its tax status in December 2005.

(c)	Other consists of general and administrative expense, interest income, interest expense and income tax expense.

(d)

Long-term assets for our Natural Gas Services segment increased as of June 30, 2007 as a result of our Southern Oklahoma asset acquisition of approximately $181.1 million (unaudited) in May 2007. Long-term assets for our Natural Gas Services segment include the effects of our 25% equity interest in East Texas, our 40% equity interest in Discovery and the Swap acquired in July 2007.

(e)	Other non-current assets not allocable to segments consist of restricted investments, unrealized gains on non-trading derivative and hedging instruments, and other non-current assets.

19. Quarterly Financial Data (Unaudited)

In July 2007, we acquired our 25% limited liability company interest in East Texas, our 40% limited liability company interest in Discovery and the Swap. Accordingly, the results of operations by quarter have been retroactively adjusted for to include the results of our wholesale propane logistics business, and for East Texas, Discovery and the Swap, for all periods presented.

Our consolidated results of operations by quarter, as previously reported, for the six months ended June 30, 2007 and the years ended December 31, 2006 and 2005 were as follows ($ in millions, except per unit amounts):


2007	First		Second		Six Months Ended June 30, 2007
Total operating revenues	$	240.1	$	186.9	$	427.0
Operating income	$	14.4	$	4.0	$	18.4
Net income	$	12.5	$	0.5	$	13.0
Limited partners’ interest in net income (a)	$	12.2	$	0.2	$	12.4
Basic net income per limited partner unit (a)	$	0.58	$	0.01	$	0.60


2006	First		Second		Third		Fourth		Year Ended December 31, 2006
Total operating revenues	$	265.4	$	160.1	$	162.8	$	207.5	$	795.8
Operating income	$	9.1	$	9.3	$	7.3	$	12.2	$	37.9
Net income	$	8.0	$	8.3	$	6.1	$	10.6	$	33.0
Limited partners’ interest in net income (a)(b)	$	5.3	$	8.6	$	9.5	$	11.1	$	34.6
Basic net income per limited partner unit (a)(b)	$	0.30	$	0.47	$	0.51	$	0.55	$	1.90


2005	First		Second		Third		Fourth		Year Ended December 31, 2005
Total operating revenues	$	264.4	$	202.5	$	285.0	$	392.4	$	1,144.3
Operating income	$	15.1	$	7.2	$	2.7	$	22.7	$	47.7
Net income	$	11.9	$	7.4	$	6.0	$	19.2	$	44.5
Limited partners’ interest in net income (a)(c)	$	—	$	—	$	—	$	4.6	$	4.6
Basic net income per limited partner unit (a)(c)	$	—	$	—	$	—	$	0.20	$	0.20

Our combined results of operations by quarter for our 25% limited liability company interest in East Texas, our 40% limited liability company interest in Discovery and the Swap for the six months ended June 30, 2007 and the years ended December 31, 2006 and 2005 were as follows ($ in millions):


2007	First			Second			Six Months Ended June 30, 2007
Total operating revenues	$	(2.9	)	$	(5.8	)	$	(8.7	)
Operating loss	$	(2.9	)	$	(5.8	)	$	(8.7	)
Net income	$	3.3		$	0.3		$	3.6
Limited partners’ interest in net income		N/A			N/A			N/A
Basic net income per limited partner unit		N/A			N/A			N/A

2006

First

Second

Third

Fourth

Year Ended
December 31,
2006

Total operating revenues

N/A

Operating income

N/A

Net income (loss)

8.3

7.4

8.2

5.0

28.9

Limited partners’ interest in net income

N/A

Basic net income per limited partner unit

N/A

2005

First

Second

Third

Fourth

Year Ended
December 31,

2005

Total operating revenues

N/A

Operating income

N/A

Net income (loss)

6.1

5.1

4.0

10.1

25.3

Limited partners’ interest in net income

N/A

Basic net income per limited partner unit

N/A

Our consolidated results of operations by quarter for the six months ended June 30, 2007 and for the years ended December 31, 2006 and 2005 were as follows ($ in millions, except per unit amounts):


2007	First		Second			Six Months Ended June 30, 2007
Total operating revenues	$	237.2	$	181.1		$	418.3
Operating income (loss)	$	11.5	$	(1.8	)	$	9.7
Net income	$	15.8	$	0.8		$	16.6
Limited partners’ interest in net income (a)	$	12.2	$	0.2		$	12.4
Basic net income per limited partner unit (a)	$	0.58	$	0.01		$	0.60


2006	First		Second		Third		Fourth		Year Ended December 31, 2006
Total operating revenues	$	265.4	$	160.1	$	162.8	$	207.5	$	795.8
Operating income	$	9.1	$	9.3	$	7.3	$	12.2	$	37.9
Net income	$	16.3	$	15.7	$	14.3	$	15.6	$	61.9
Limited partners’ interest in net income (a)(b)	$	5.3	$	8.6	$	9.5	$	11.1	$	34.6
Basic net income per limited partner unit (a)(b)	$	0.30	$	0.47	$	0.51	$	0.55	$	1.90


2005	First		Second		Third		Fourth		Year Ended December 31, 2005
Total operating revenues	$	264.4	$	202.5	$	285.0	$	392.4	$	1,144.3
Operating income	$	15.1	$	7.2	$	2.7	$	22.7	$	47.7
Net income	$	18.0	$	12.5	$	10.0	$	29.3	$	69.8
Limited partners’ interest in net income (a)(c)	$	—	$	—	$	—	$	4.6	$	4.6
Basic net income per limited partner unit (a)(c)	$	—	$	—	$	—	$	0.20	$	0.20

(a)	Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our interest in East Texas, Discovery and the Swap for all periods presented.

(b)	Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our wholesale propane logistics business for the period January 1, 2006 through October 31, 2006.

(c)	Total limited partners’ interest in net income and basic income per limited partner unit is calculated using net income earned by us from December 7, 2005 through December 31, 2005, excluding the results from our wholesale propane logistics business.

20. Subsequent Events

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We will use the mark-to-market method of accounting for all commodity cash flow hedges beginning in July 2007. As a result, the remaining net loss of $2.0 million deferred in AOCI as of June 30, 2007 will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings.

In August 2007, we entered into interest rate swap agreements to convert $200.0 million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. These interest rate swaps commenced on September 21, 2007, expire on June 21, 2012 and re-price prospectively approximately every 90 days. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation.

In conjunction with DCP Midstream, LLC’s acquisition of MEG in August 2007, we acquired certain subsidiaries of MEG from DCP Midstream, LLC for aggregate consideration of approximately $165.8 million, subject to final closing adjustments. The consideration consisted of approximately $153.8 million of cash and the issuance of 275,735 common units to an affiliate of DCP Midstream, LLC that were valued at approximately $12.0 million. We have incurred post-closing purchase price adjustments to date that include a liability of $9.0 million for net working capital and general and administrative charges. The subsidiaries of MEG own gathering, processing and compression assets in the Piceance and Powder River producing basins. The Piceance Basin assets consist of a 70 percent operating interest in the 31-mile Collbran Valley Gas Gathering system joint venture, which gathers and processes natural gas from over 20,000 dedicated acres in western Colorado. The processing facility capacity is currently being expanded from 60 MMcf/d to 120 MMcf/d. The other partners in the joint venture, Plains Exploration and Delta Petroleum, are also the producers on the system. The Powder River Basin assets include the 1,324-mile Douglas gas gathering system, which gathers approximately 30 MMcf/d of gas and covers more than 4,000 square miles in Wyoming. Also included in the transaction are the idle Painter Unit fractionator and Millis terminal, and associated NGL pipelines in southwest Wyoming. DCP Midstream, LLC will manage and operate these assets on our behalf. We financed this transaction with borrowings under our amended credit facility of $120.0 million, the issuance of common units through a private placement with certain institutional investors and cash on hand. In August 2007, we sold 2,380,952 common units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate. In connection with this common unit purchase agreement, we have a registration rights agreement that requires us to register the units within 90 days of the close of the private placement, and have filed a registration statement with the SEC. In addition, the registration rights agreement requires us to use our commercially reasonable efforts to cause the registration statement to become effective within 180 days of the closing of the private placement. If the registration statement covering the common units is not declared effective by the SEC within 180 days of the closing of the private placement, then we will be liable to the purchasers for liquidated damages of 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for the first 60 days following the 180th day, increasing by an additional 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period.

In August 2007, our Omnibus Agreement with DCP Midstream, LLC was amended to increase the annual fee by $0.6 million for general and administrative expenses payable to DCP Midstream, LLC under the agreement to account for additional services provided to us and extend the term for all general and administrative expenses under the agreement through December 31, 2009. The Omnibus Agreement was further amended in August 2007 to include an additional annual fee of $1.6 million in connection with our acquisition of the MEG subsidiaries, described above.

DCP MIDSTREAM PARTNERS, LP

SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


	Balance at Beginning of Period		Charged to Consolidated Statements of Operations		Deductions/ Other			Credit to Consolidated Statements of Operations			Balance at End of Period
	($ in millions)
December 31, 2006
Allowance for doubtful accounts	$	0.3	$	0.3	$	(0.3	)	$	—		$	0.3
Environmental		0.1		—		—			—			0.1
Other (a)		—		0.3		—			—			0.3

	$	0.4	$	0.6	$	(0.3	)	$	—		$	0.7

December 31, 2005
Allowance for doubtful accounts	$	0.3	$	0.1	$	—		$	(0.1	)	$	0.3
Environmental		—		0.2		(0.1	)		—			0.1
Other (a)		1.3		—		(1.3	)		—			—

	$	1.6	$	0.3	$	(1.4	)	$	(0.1	)	$	0.4

December 31, 2004
Allowance for doubtful accounts	$	0.3	$	—	$	—		$	—		$	0.3
Environmental		—		—		—			—			—
Other (a)		1.3		—		—			—			1.3

	$	1.6	$	—	$	—		$	—		$	1.6

(a)	Principally consists of other contingency liabilities, which are included in other current liabilities.