Edgar Filing: Spectra Energy Corp.

Amended Form 10-K for fiscal year ended December 31, 2007

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2007 or

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

For the transition period from to

Commission file number 1-33007

SPECTRA ENERGY CORP

(Exact name of registrant as specified in its charter)


Delaware		20-5413139
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5400 Westheimer Court, Houston, Texas		77056
(Address of principal executive offices)		(Zip Code)

713-627-5400

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.001		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2007: $16,400,000,000.

Number of shares of Common Stock, $0.001 par value, outstanding at February 19, 2008: 632,536,965

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K of Spectra Energy Corp (Spectra Energy) for the fiscal year ended December 31, 2007 is being filed for the purpose of providing separate audited financial statements and the related schedule of DCP Midstream, LLC in accordance with Rule 3-09 of Regulation S-X. These audited financial statements and the related schedule are included in Item 15. Exhibits and Financial Statement Schedule. This amendment does not update or modify in any way the results of operations, financial position, cash flows or other disclosures in Spectra Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, and does not reflect events occurring after the original filing date of said Form 10-K of February 29, 2008.

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

The following financial statements and supplemental schedules were filed as part of Spectra Energy’s Form 10-K filed February 29, 2008:

Spectra Energy Corp:

Report of Independent Registered Accounting Firm

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Balance Sheets as of December 31, 2007 and 2006

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Statements of Stockholders’/Member’s Equity and Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005

Notes to the Consolidated Financial Statements

TEPPCO Partners, L.P.:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2005 and 2004

Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003

Notes to Consolidated Financial Statements

The following financial statements are included herein:

DCP Midstream, LLC:

Independent Auditors’ Report

Consolidated Balance Sheets as of December 31, 2007 and 2006

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Statements of Members’ Equity for the Years Ended December 31, 2007, 2006 and 2005

Notes to Consolidated Financial Statements

(a)(2) Financial Statement Schedules

The following financial statement schedule was filed as part of Spectra Energy’s Form 10-K filed February 29, 2008:

Spectra Energy Corp:

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2007, 2006 and 2005

The following financial statement schedule is included herein:

DCP Midstream, LLC:

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2007, 2006 and 2005

(a)(3) Exhibits — See Exhibit Index immediately following the signature page.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


				SPECTRA ENERGY CORP

Date: March 20, 2008				/s/ Gregory L. Ebel
				Gregory L. Ebel
				Group Executive and Chief Executive Officer

EXHIBIT INDEX


Exhibit No.		Exhibit Description

*23.1		Consent of Independent Auditors.

*31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.

DCP MIDSTREAM, LLC

CONSOLIDATED FINANCIAL STATEMENTS

TABLE OF CONTENTS


		Page

Independent Auditors’ Report		F-1

Consolidated Balance Sheets		F-2

Consolidated Statements of Operations and Comprehensive Income		F-3

Consolidated Statements of Cash Flows		F-4

Consolidated Statements of Members’ Equity		F-5

Notes to Consolidated Financial Statements		F-6

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

DCP Midstream, LLC

Denver, Colorado

We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DCP Midstream, LLC and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 7, 2008 (March 20, 2008 as to the offering described in Note 19)

F-1

DCP MIDSTREAM, LLC

CONSOLIDATED BALANCE SHEETS

As of December 31, 2007 and 2006

(millions)


	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	71		$	68
Short-term investments		9			437
Accounts receivable:
Customers, net of allowance for doubtful accounts of $5 million and $3 million, respectively		1,254			933
Affiliates		386			283
Other		48			56
Inventories		117			87
Unrealized gains on mark-to-market and hedging instruments		301			242
Other		62			23

Total current assets		2,248			2,129

Property, plant and equipment, net		4,443			3,869
Restricted investments		101			102
Investments in unconsolidated affiliates		204			204
Intangible assets, net		312			58
Goodwill		556			421
Unrealized gains on mark-to-market and hedging instruments		69			29
Deferred income taxes		7			4
Other non-current assets		38			33
Other non-current assets—affiliates		27			47

Total assets	$	8,005		$	6,896

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,499		$	1,490
Affiliates		122			92
Other		54			42
Unrealized losses on mark-to-market and hedging instruments		347			216
Distributions payable to members		123			127
Accrued interest payable		56			47
Accrued taxes		55			27
Other		204			136

Total current liabilities		2,460			2,177

Deferred income taxes		16			17
Long-term debt		2,930			2,115
Unrealized losses on mark-to-market and hedging instruments		120			33
Other long-term liabilities		323			226
Non-controlling interests		193			71
Commitments and contingent liabilities
Members’ equity:
Members’ interest		1,974			2,107
Retained earnings		—			153
Accumulated other comprehensive loss		(11	)		(3	)

Total members’ equity		1,963			2,257

Total liabilities and members’ equity	$	8,005		$	6,896

See Notes to Consolidated Financial Statements.

F-2

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

Years Ended December 31, 2007, 2006 and 2005

(millions)


	2007			2006			2005
Operating revenues:
Sales of natural gas and petroleum products	$	10,009		$	9,137		$	10,011
Sales of natural gas and petroleum products to affiliates		2,884			2,813			2,785
Transportation, storage and processing		304			308			253
Trading and marketing (losses) gains, net		(43	)		77			(15	)

Total operating revenues		13,154			12,335			13,034

Operating costs and expenses:
Purchases of natural gas and petroleum products		10,097			9,322			10,133
Purchases of natural gas and petroleum products from affiliates		781			789			830
Operating and maintenance		510			462			447
Depreciation and amortization		316			284			287
General and administrative		258			234			195
Gain on sale of assets		(3	)		(28	)		(2	)

Total operating costs and expenses		11,959			11,063			11,890

Operating income		1,195			1,272			1,144
Gain on sale of general partner interest in TEPPCO		—			—			1,137
Equity in earnings of unconsolidated affiliates		29			20			22
Non-controlling interest in loss (income)		15			(15	)		1
Interest income		16			26			26
Interest expense		(170	)		(145	)		(154	)

Income before income taxes		1,085			1,158			2,176
Income tax expense		(11	)		(23	)		(9	)

Income from continuing operations		1,074			1,135			2,167
Income from discontinued operations, net of income taxes		—			—			3

Net income		1,074			1,135			2,170
Other comprehensive (loss) income:
Foreign currency translation adjustment		—			—			(8	)
Canadian business distributed to Duke Energy		—			—			(70	)
Net unrealized (losses) gains on cash flow hedges		(8	)		5			—
Reclassification of cash flow hedges into earnings		—			—			1

Total other comprehensive (loss) income		(8	)		5			(77	)

Total comprehensive income	$	1,066		$	1,140		$	2,093

See Notes to Consolidated Financial Statements.

F-3

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2007, 2006 and 2005

(millions)


	2007			2006			2005
Cash flows from operating activities:
Net income	$	1,074		$	1,135		$	2,170
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—			—			(3	)
Gain from sale of equity investment in TEPPCO		—			—			(1,137	)
Gain on sale of assets		(3	)		(28	)		(2	)
Depreciation and amortization		316			284			287
Equity in earnings of unconsolidated affiliates, net of distributions		3			—			15
Deferred income tax (benefit) expense		(1	)		17			(2	)
Non-controlling interest in (loss) income		(15	)		15			(1	)
Other, net		11			(3	)		2
Changes in operating assets and liabilities which provided (used) cash, net of effects from acquisitions:
Accounts receivable		(398	)		314			(432	)
Inventories		(30	)		23			(37	)
Net unrealized losses (gains) on mark-to-market and hedging instruments		99			(1	)		9
Accounts payable		33			(495	)		910
Accrued interest payable		9			1			(14	)
Other		50			(16	)		(12	)

Net cash provided by continuing operations		1,148			1,246			1,753
Net cash provided by discontinued operations		—			—			11

Net cash provided by operating activities		1,148			1,246			1,764

Cash flows from investing activities:
Capital and acquisition expenditures		(600	)		(325	)		(212	)
Acquisition of Momentum Energy Group, Inc., net of cash acquired		(604	)		—			—
Investments in unconsolidated affiliates		(4	)		(44	)		(24	)
Distributions from unconsolidated affiliates		—			2			—
Purchases of available-for-sale securities		(15,812	)		(19,666	)		(17,986	)
Proceeds from sales of available-for-sale securities		16,243			20,121			17,260
Proceeds from sales of assets		1			81			53
Proceeds from sale of general partner interest in TEPPCO		—			—			1,100
Other		2			—			9

Net cash (used in) provided by continuing operations		(774	)		169			200
Net cash used in discontinued operations		—			—			(13	)

Net cash (used in) provided by investing activities		(774	)		169			187

Cash flows from financing activities:
Payment of dividends and distributions to members		(1,364	)		(1,451	)		(2,313	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		229			—			206
Contribution received from ConocoPhillips		—			—			398
Proceeds from debt		1,477			378			408
Payment of debt		(667	)		(320	)		(607	)
Payment of debt acquired		(20	)		—			—
Loans made to Duke Capital LLC and ConocoPhillips		—			—			(1,100	)
Repayment of loans by Duke Capital LLC and ConocoPhillips		—			—			1,100
Net cash paid to non-controlling interests		(22	)		(10	)		3
Other		(4	)		(3	)		(2	)

Net cash used in continuing operations		(371	)		(1,406	)		(1,907	)
Net cash used in discontinued operations		—			—			(44	)
Net cash used in financing activities		(371	)		(1,406	)		(1,951	)

Net increase in cash and cash equivalents		3			9			—
Cash and cash equivalents, beginning of period		68			59			59

Cash and cash equivalents, end of period	$	71		$	68		$	59

See Notes to Consolidated Financial Statements.

F-4

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

Years Ended December 31, 2007, 2006 and 2005

(millions)


	Members’ Interest			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2005	$	1,709		$	909		$	69		$	2,687
Dividends and distributions		—			(2,414	)		—			(2,414	)
Distribution of Canadian business		—			(254	)		(70	)		(324	)
Contributions		398			—			—			398
Net income		—			2,170			—			2,170
Foreign currency translation adjustment		—			—			(8	)		(8	)
Reclassification of cash flow hedges into earnings		—			—			1			1

Balance, December 31, 2005		2,107			411			(8	)		2,510
Dividends and distributions		—			(1,393	)		—			(1,393	)
Net income		—			1,135			—			1,135
Net unrealized gains on cash flow hedges		—			—			5			5

Balance, December 31, 2006		2,107			153			(3	)		2,257
Dividends and distributions		(133	)		(1,227	)		—			(1,360	)
Net income		—			1,074			—			1,074
Net unrealized losses on cash flow hedges		—			—			(8	)		(8	)

Balance, December 31, 2007	$	1,974		$	—		$	(11	)	$	1,963

See Notes to Consolidated Financial Statements.

F-5

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

1. General and Summary of Significant Accounting Policies

Basis of Presentation—DCP Midstream, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs.

We formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. DCP Partners completed their initial public offering in December 2005. As of December 31, 2007 and 2006, respectively, we owned a 33.9% and 40.7% limited partnership interest and a 1.5% and 2.0% general partnership interest in DCP Partners, as well as incentive distribution rights that entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved. As the general partner of DCP Partners, we have responsibility for its operations. Since we exercise control over DCP Partners, we account for them as a consolidated subsidiary.

Prior to January 2, 2007, we were owned 50% by Duke Energy Corporation, or Duke Energy. On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For periods prior to January 2, 2007, references to Spectra Energy are interchangeable with Duke Energy. Effective January 2, 2007, Spectra Energy refers to the newly formed public company.

In July 2005, Duke Energy transferred a 19.7% interest in us to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in us to 50% and increasing ConocoPhillips’ membership interest in us to 50%, referred to as “the 50-50 Transaction.” Included in this transaction, we distributed to Duke Energy substantially all of our Canadian business, made a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO Partners L.P., or TEPPCO, and paid a $245 million proportionate distribution to Duke Energy and ConocoPhillips. In addition, ConocoPhillips contributed cash of $398 million to us. Under the terms of the Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. At December 31, 2007 and 2006, there were no remaining restricted investment balances related to this contribution.

We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights.

F-6

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

Use of Estimates—Conformity with accounting principles generally accepted in the United States of America, or GAAP, requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from these estimates.

Cash and Cash Equivalents—Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

Short-Term and Restricted Investments—We may invest available cash balances in various financial instruments, such as commercial paper, money market instruments and tax-exempt debt securities that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2007 or 2006. Restricted investments consist of collateral for DCP Partners’ term loan. The costs, including accrued interest on investments, approximates fair value due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.

Inventories—Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheets.

Accounting for Risk Management and Derivative Activities and Financial Instruments—Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We are using the mark-to-market method of accounting for all commodity derivative instruments beginning in July 2007. As a result, the remaining net loss deferred in AOCI is being reclassified to sales of natural gas and petroleum products through December 2011, as the derivative transactions impact earnings.

Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.

We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are

F-7

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:


Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market method^b	Net basis in trading and marketing gains and losses

Non-Trading Derivatives:

Cash Flow Hedge^a	Hedge method^c	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item

Fair Value Hedge	Hedge method^c	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item

Normal Purchase or Normal Sale	Accrual method^d	Gross basis upon settlement in the corresponding consolidated statements of operations and comprehensive income category based on purchase or sale

Non-Trading Derivatives	Mark-to-market method^b	Net basis in trading and marketing gains and losses

a	Effective July 1, 2007, all commodity cash flow hedges are classified as non-trading derivative activity. Our interest rate swaps continue to be accounted for as cash flow hedges.

b	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 and comprehensive income in trading and marketing gains and losses during the current period.

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 mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations and comprehensive income for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations and comprehensive income in the same category as the related hedged item.

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

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

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as AOCI and the ineffective portion is recorded in the consolidated statements of operations and comprehensive income. 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 and comprehensive income in

F-8

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance 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.

For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations and comprehensive income.

Valuation—When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.

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

Property, Plant and Equipment—Property, plant and equipment are recorded at original 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.

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

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

We evaluate our investments in unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses the fair value of our unconsolidated affiliates using

F-9

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.

Intangible Assets and Goodwill—Intangible assets consist primarily of commodity sales and purchase contracts and relationships, which are amortized on a straight-line basis over the term of the contract or anticipated relationship, ranging from one to 25 years. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business.

We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, the excess of the carrying value over the fair value is recognized as an impairment loss.

Long-Lived Assets—We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:

•

a significant adverse change in legal factors or business climate;

•

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

•

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

•

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

•

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

•

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

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

Upon classification as held for sale, a long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheets.

F-10

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

If an asset held for sale or sold (1) has clearly distinguishable operations and cash flows, generally at the plant level, (2) has direct cash flows of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.

Unamortized Debt Premium, Discount and Expense—Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheets within long-term debt. These unamortized expenses are recorded on the consolidated balance sheets as other non-current assets.

Distributions—Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each member’s tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips, and prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the years ended December 31, 2007, 2006 and 2005, we paid distributions of $497 million, $650 million and $389 million, respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. The LLC Agreement restricts payment of dividends except with the approval of both members. During the years ended December 31, 2007, 2006 and 2005, we paid dividends of $867 million, $801 million and $1,925 million, respectively, to the members. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and $580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $867 million and $801 million paid during the years ended December 31, 2007 and 2006, are comprised of proportionate distributions to Duke Energy and ConocoPhillips, allocated in accordance with our partners’ respective ownership percentages.

DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our limited partner interest in DCP Partners primarily consists of subordinated units and common units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the

F-11

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. 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 DCP Partners’ partnership agreement, have been met. The subordination period has an early termination provision that permitted 50% of the subordinated units, or 3,571,428 units, to convert to common units in February 2008 and permits 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 DCP Partners’ partnership agreement are satisfied. During the years ended December 31, 2007 and 2006, DCP Partners paid distributions of approximately $25 million and $13 million, respectively, to its public unitholders. In addition to our 33.9% limited partnership interests we hold a 1.5% general partnership interest, as well as incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

Foreign Currency Translation—We translated assets and liabilities of our Canadian operations, where the Canadian dollar was the functional currency, at the period-end exchange rates. Revenues and expenses were translated using average monthly exchange rates during the period, which approximates the exchange rates at the time of each transaction during the period. Foreign currency translation adjustments are included in the consolidated statements of operations and of comprehensive income. In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. As a result, there were no translation gains or losses in AOCI at December 31, 2007, 2006 and 2005.

Revenue Recognition—We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and NGL fractionation, transportation, gathering, treating, processing and storage, as well as 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 raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.

•

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

•

Percent-of-proceeds/index arrangements—Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percent-of-proceeds/index arrangements correlate directly with the price of natural gas and/or NGLs.

F-12

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

•

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

Our trading and marketing of natural gas and petroleum products, consists of physical purchases and sales, as well as derivative instruments.

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

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

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

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

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

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

Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2007, 2006 and 2005.

F-13

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable—other as of December 31, 2007 and 2006 were imbalances totaling $48 million and $45 million, respectively. Included in the consolidated balance sheets as accounts payable—other, as of December 31, 2007 and 2006 were imbalances totaling $54 million and $42 million, respectively.

Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in each of the past three years. Sales to ConocoPhillips, including its 50% owned equity method investment, Chevron Phillips Chemical Company LLC, or CP Chem, totaled approximately $2,787 million, $2,677 million, and $2,513 million during 2007, 2006 and 2005, respectively.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2007 and 2006, included in the consolidated balance sheets, totaled $6 million in both periods recorded as other current liabilities, and totaled $6 million in both periods recorded as other long-term liabilities.

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

Through July 1, 2005, we accounted for stock-based compensation by measuring the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

Effective January 1, 2006, we adopted the provisions of Statement of Financial Accounting Standard, or SFAS, No. 123(R) (Revised 2004) “Share-Based Payment,” or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.

F-14

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for 2005 presented in these consolidated financial statements have not been restated. 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.

The following table shows what net income would have been if the fair value recognition provisions of SFAS 123R had been applied to all stock-based compensation awards for the year ended December 31, 2005.


	Year Ended December 31, 2005
	(millions)
Net income, as reported	$	2,170
Add: stock-based compensation expense included in reported net income		3
Deduct: total stock-based compensation expense determined under fair value-based method for all awards		(3	)

Pro forma net income	$	2,170

Accounting for Sales of Units by a Subsidiary—We account for sales of units by a subsidiary by recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. As a result, we have deferred approximately $228 million of gain on sale of common units in DCP Partners, which is included in other long-term liabilities in the consolidated balance sheets. This gain is comprised of approximately $36 million related to DCP Partners’ private placement in August 2007, $43 million related to DCP Partners’ private placement in June 2007, and approximately $149 million related to DCP Partners’ initial public offering in December 2005. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

Income Taxes—We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes.

We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.

Recent Accounting Pronouncements—SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51,” or SFAS 160. In December 2007, the FASB issued SFAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 is effective for us on January 1, 2009. Due to the recency of this pronouncement, we have not assessed the impact of SFAS 160 on our consolidated results of operations, cash flows or financial position.

F-15

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

SFAS No. 141(R) “Business Combinations (revised 2007),” or SFAS 141(R). In December, 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively upon adoption, we will account for all transactions with closing dates subsequent to the adoption date in accordance with the provisions of the standard.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that 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 elected the fair value option relative to any of our financial assets and liabilities which are not otherwise required to be measured at fair value by other accounting standards. Therefore, there is no effect of adoption reflected in our consolidated results of operations, cash flows or financial position.

SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. The standard establishes a framework for measuring fair value and expands the disclosure requirements surrounding assumptions made in the measurement of fair value.

The adoption of this standard will result in us making slight changes to our valuation methodologies to incorporate the marketplace participant view as prescribed by SFAS 157. Such changes will include, but will not be limited to, changes in valuation policies to reflect an exit price methodology, the effect of considering our own non-performance risk on the valuation of liabilities, and the effect of any change in our credit rating or standing. As a result of adopting SFAS 157, we estimate a cumulative effect transition adjustment of an after-tax increase to members’ equity of approximately $8 million. This transition adjustment will directly affect the beginning balance of members’ equity.

Pursuant to FASB Financial Staff Position 157-2, the FASB issued a partial deferral of the implementation of SFAS 157 as it relates to all non-financial assets and liabilities where fair value is the required measurement attribute by other accounting standards. While, we have adopted SFAS 157 for all financial assets and liabilities (primarily as a result of derivative trading activity) effective January 1, 2008, we have not assessed the impact that the adoption of SFAS 157 will have on our non-financial assets and liabilities.

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

F-16

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

2. Acquisitions and Dispositions

Acquisitions

Acquisition of Various Gathering, Pipeline and Compression Assets—On August 29, 2007, we acquired the stock of Momentum Energy Group, Inc., or MEG, for approximately $635 million plus closing adjustments of approximately $11 million. The results of MEG’s operations have been included in the consolidated financial statements since that date. As a result of the acquisition, we expanded our operations into the Fort Worth, Piceance and Powder River producing basins, thus diversifying our business into new areas. We funded our portion of this acquisition with a 364-day bridge loan for $450 million, which was paid off in September 2007 with proceeds from the issuance of the $450 million principal amount of 6.75% Senior Notes, as well as cash on hand. See further discussion of this transaction in the Contributions to DCP Partners section below.

Under the purchase method of accounting, the assets and liabilities of MEG were recorded at their respective fair values as of the date of the acquisition, and we recorded goodwill of approximately $135 million. The goodwill amount recognized relates primarily to projected growth in the Fort Worth and Piceance producing basins due to significant natural gas reserves and high level of drilling activity. We expect all of the goodwill to be tax deductible. The values of certain assets and liabilities are preliminary, and are subject to adjustment as additional information is obtained. When finalized, material adjustments to goodwill may result.

The purchase price allocation is as follows (millions):


Cash	$	42
Receivables		23
Other assets		2
Property, plant and equipment		278
Intangible assets		254
Goodwill		135
Payables		(18	)
Other liabilities		(27	)
Current debt		(20	)
Minority interest		(23	)

Total allocation of purchase price	$	646

In May 2007, DCP Partners acquired certain gathering and compression assets located in southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181 million.

In the fourth quarter of 2005, we entered into an agreement to purchase certain pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million, which are regulated by the Federal Energy Regulatory Commission, or FERC. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we have filed with the FERC for a certificate to operate as an interstate pipeline. This acquisition is expected to close in 2008.

Acquisition of Additional Equity Interests—In December 2006, we acquired an additional one-third interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own two-thirds of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering

F-17

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

pipeline system in the Gulf of Mexico. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method.

In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.

In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services LLC, or Discovery, from Williams Energy, LLC for a purchase price of $13 million. Discovery is an unconsolidated affiliate, which, prior to this transaction, was 33.33% owned by us, and subsequent to this transaction is 40% owned by us. Discovery owns and operates an interstate pipeline, a condensate handling facility, a cryogenic gas processing plant and other gathering assets in deepwater offshore Louisiana.

Dispositions

Disposition of Various Gathering, Transmission and Processing Assets—During the first quarter of 2006, we sold assets totaling $57 million, for proceeds of $85 million, and we recognized a gain of $28 million.

In August 2005, we sold certain gas gathering facilities in Kansas and Oklahoma for a sales price of approximately $11 million. No gain or loss was recognized.

In February 2005, we exchanged certain processing plant assets in Wyoming for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.

In February 2005, we sold certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming for approximately $28 million.

Disposition of Equity Interests—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid its outstanding borrowings in full in March 2005. Duke Capital, LLC repaid its outstanding borrowings in full in July 2005.

F-18

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Distribution of Canadian Business to Duke Energy—In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):


Assets:
Cash	$	44
Accounts receivable		18
Other assets		1
Property, plant and equipment, net		291
Goodwill		18

Total assets	$	372

Liabilities:
Accounts payable	$	11
Other current liabilities		4
Current and long-term debt		1
Deferred income taxes		20
Other long-term liabilities		12

Total liabilities	$	48

Net assets of Canadian business distributed to Duke Energy	$	324

We routinely sell assets that comprise a component of the Company, and are recorded as discontinued operations, but are not individually significant. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented.

There were no assets accounted for as discontinued operations for the years ended December 31, 2007 or 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations.


	For the Year Ended December 31, 2005
	(millions)
Operating revenues	$	35

Pre-tax operating income	$	4
Income tax expense		(1	)

Income from discontinued operations	$	3

Contributions to DCP Partners

MEG—Concurrent with our acquisition of the stock of MEG in August 2007, DCP Partners acquired certain subsidiaries of MEG from us for $166 million plus post-closing purchase price adjustments of approximately $9 million. These subsidiaries of MEG own assets in the Piceance Basin, including a 70% operated interest in the

F-19

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Collbran Valley Gas Gathering system joint venture in western Colorado, and assets in the Powder River Basin, including the Douglas gas gathering system in Wyoming. DCP Partners financed this transaction with $120 million of revolver and term loan borrowings under DCP Partners’ Amended Credit Agreement, the issuance of common units through a private placement with certain institutional inventors and cash on hand. In August 2007, DCP Partners issued 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate. As a result of this transaction, the omnibus agreement with DCP Partners was amended to increase the annual fee payable to us by DCP Partners by $2 million for incremental general and administrative expenses. We will continue to operate these assets and these assets will continue to be included in our financial statements, through the consolidation of DCP Partners.

DCP East Texas Holdings, LLC and Discovery Producer Services LLC—In July 2007, we contributed to DCP Partners our 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, our 40% limited liability company interest in Discovery and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas, while third parties still own the other 60% limited liability interest in Discovery. DCP Partners financed the cash portion of this transaction with borrowings under its existing credit facility. We will continue to operate East Texas and both of these assets will continue to be included in our financial statements, through the consolidation of DCP Partners.

Wholesale Propane Logistics Business—In November 2006, we contributed our wholesale propane logistics business to DCP Partners for consideration of approximately $83 million, including $77 million in cash ($10 million of which was paid in January 2007 upon completion of construction of a new propane terminal), and $6 million in Class C units. DCP Partners financed this transaction with its existing credit facility and the issuance of Class C units, which were subsequently converted to common units on July 2, 2007. As a result of this transaction, the omnibus agreement with DCP Partners was amended to increase the annual fee payable to us by DCP Partners by $2 million for incremental general and administrative expenses. We will continue to operate these assets and these assets will continue to be included in our financial statements, through the consolidation of DCP Partners.

F-20

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

3. Agreements and Transactions with Affiliates

The following table summarizes the transactions with affiliates:


	For the Years Ended, December 31,
	2007		2006		2005
	(millions)
Spectra Energy:
Sales of natural gas and petroleum products to affiliates	$	2	$	—	$	—
Transportation, storage and processing	$	4	$	—	$	—
Purchases of natural gas and petroleum products from affiliates	$	123	$	—	$	—
Operating and general and administrative expenses	$	13	$	—	$	—
Duke Energy:
Sales of natural gas and petroleum products to affiliates	$	—	$	41	$	109
Transportation, storage and processing	$	—	$	18	$	2
Purchases of natural gas and petroleum products from affiliates	$	—	$	137	$	130
Operating and general and administrative expenses	$	—	$	30	$	44
Interest income	$	—	$	—	$	8
ConocoPhillips (a):
Sales of natural gas and petroleum products to affiliates	$	2,787	$	2,677	$	2,513
Transportation, storage and processing	$	17	$	12	$	11
Purchases of natural gas and petroleum products from affiliates	$	489	$	492	$	556
General and administrative expenses	$	2	$	5	$	—
Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	95	$	95	$	163
Transportation, storage and processing	$	23	$	20	$	20
Purchases of natural gas and petroleum products from affiliates	$	169	$	160	$	144

(a)	Includes ConocoPhillips’ 50% owned equity method investment, Chevron Phillips Chemical Company LLC

Spectra Energy

Commodity Transactions—We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell commodities and provide services to Spectra Energy in the ordinary course of business.

Included in the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2007 and 2006, are insurance recovery receivables of $27 million and $47 million, respectively, and included in accounts receivable—affiliates as of December 31, 2007 and 2006, are other receivables of $2 million and $8 million, respectively. Prior to January 2, 2007, these receivables were from an insurance provider that is a subsidiary of Duke Energy. In connection with the Spectra spin, Spectra Energy is responsible for these insurance liabilities. During the years ended December 31, 2007, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $4 million, $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.

Duke Energy

In connection with the Spectra spin, Duke Energy is not considered a related party for reporting periods after January 2, 2007.

F-21

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Commodity Transactions—In 2006, we sold a portion of our residue gas and NGLs to, purchased raw natural gas and other petroleum products from, and provided gathering and transportation services to Duke Energy and their subsidiaries.

Services Agreement—Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

In connection with the Spectra spin, as of December 31, 2007, our corporate operations, Spectra Energy, or third party service providers have assumed responsibility for all services previously provided to us by Duke Energy.

In the fourth quarter of 2006, an insurance provider that is a subsidiary of Duke Energy agreed to settle an insurance claim, related to a damaged underground storage facility, for approximately $21 million. We had recorded a receivable in 2005 related to this claim for approximately $4 million. Upon receipt of the cash in December 2006, we relieved the receivable and recorded business interruption insurance recoveries of approximately $16 million, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.

ConocoPhillips

Long-term NGLs Purchases Contract and Transactions—We sell a portion of our residue gas and NGLs to ConocoPhillips and its subsidiaries, including Chevron Phillips Chemical Company LLC, or CP Chem, a 50% equity investment of ConocoPhillips. In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreements, or the NGL Agreements, with ConocoPhillips and CP Chem, ConocoPhillips and CP Chem have the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The NGL Agreements also grant ConocoPhillips and CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary terms of the agreements are effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

Transactions with other unconsolidated affiliates

We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.

In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving

F-22

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid their outstanding borrowings in full in March 2005. Duke Capital LLC repaid their outstanding borrowings in full in July 2005.

Estimates related to affiliates

Revenue for goods and services provided but not invoiced to affiliates is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to quarter end relating to estimated revenues and purchases recorded at December 31, 2007, 2006 and 2005.

4. Inventories

Inventories were as follows:


	December 31,
	2007		2006
	(millions)
Natural gas held for resale	$	39	$	34
NGLs		78		53

Total inventories	$	117	$	87

5. Property, Plant and Equipment

Property, plant and equipment by classification was as follows:


	Depreciable Life	December 31,
	Depreciable Life	2007			2006
		(millions)
Gathering	15 - 30 years	$	3,233		$	2,641
Processing	25 - 30 years		2,030			1,904
Transportation	25 - 30 years		1,224			1,217
Underground storage	20 - 50 years		121			119
General plant	3 - 5 years		153			146
Construction work in progress			347			203

			7,108			6,230
Accumulated depreciation			(2,665	)		(2,361	)

Property, plant and equipment, net		$	4,443		$	3,869

Depreciation expense for the years ended December 31, 2007, 2006 and 2005 was $304 million, $275 million and $278 million, respectively. Interest capitalized on construction projects in 2007, 2006 and 2005, was approximately $4 million, $3 million and $2 million, respectively. At December 31, 2007 we had non-cancelable purchase obligations of approximately $9 million for capital projects to be completed in 2008.

F-23

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

6. Goodwill and Intangible Assets

The changes in carrying amount of goodwill are as follows:


	December 31,
	2007		2006
	(millions)
Goodwill, beginning of period	$	421	$	421
Goodwill acquired		135		—

Goodwill, end of period	$	556	$	421

The increase in goodwill during 2007 consists of the amount that we recognized in connection with our acquisition of MEG.

We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment test, as of August 31, 2007, and our interim goodwill impairment test in conjunction with the distribution of substantially all of our Canadian business to Duke Energy in conjunction with the 50-50 Transaction, in July 2005, both indicated that our reporting units’ fair values exceed their carrying or book values. Accordingly, no impairment of goodwill is indicated.

Intangible assets consist primarily of commodity sales and purchase contracts and relationships. The gross carrying amount and accumulated amortization for intangible assets are as follows:


	December 31,
	2007			2006
	(millions)
Gross carrying amount	$	398		$	132
Accumulated amortization		(86	)		(74	)

Intangible assets, net	$	312		$	58

Intangible assets increased as a result of the Southern Oklahoma and MEG acquisitions, through which $12 million and $254 million, respectively, of intangible assets were acquired. During the years ended December 31, 2007, 2006 and 2005 we recorded amortization expense of $12 million, $9 million, and $9 million, respectively. The remaining amortization periods range from less than one year to 25 years, with a weighted average remaining period of approximately 21 years.

F-24

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Estimated amortization for these contracts for the next five years and thereafter is as follows as of December 31, 2007:


Estimated Amortization
(millions)
2008	$	21
2009		20
2010		19
2011		18
2012		18
Thereafter		216

Total	$	312

7. Investments in Unconsolidated Affiliates

We have investments in the following unconsolidated affiliates accounted for using the equity method:


	2007 Ownership		December 31,
	2007 Ownership		2007		2006
			(millions)
Discovery Producer Services LLC	40.00	%	$	118	$	114
Main Pass Oil Gathering Company	66.67	%		43		47
Mont Belvieu I	20.00	%		12		11
Sycamore Gas System General Partnership	48.45	%		11		12
Tri-States NGL Pipeline, LLC	16.67	%		9		9
Black Lake Pipe Line Company	50.00	%		7		6
Other unconsolidated affiliates	Various			4		5

Total investments in unconsolidated affiliates			$	204	$	204

Discovery Producer Services LLC—Discovery operates a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana with a design capacity of 600 MMcf/d and approximately 173 miles of pipe, and several onshore laterals expanding their presence in the Gulf. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $44 million and $49 million at December 31, 2007 and 2006, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

Main Pass Oil Gathering Company—In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at both December 31, 2007 and 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.

F-25

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Mont Belvieu I—Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $10 million and $11 million at December 31, 2007 and 2006, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.

Sycamore Gas System General Partnership—Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $7 million and $9 million at December 31, 2007 and 2006, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Tri-States NGL Pipeline, LLC—Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at both December 31, 2007 and 2006 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this investment is accounted for under the equity method of accounting.

Black Lake Pipe Line Company—Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at both December 31, 2007 and 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

TEPPCO Partners, L.P.—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million.

Equity in earnings of unconsolidated affiliates amounted to the following:


	For the Years Ended December 31,
	2007			2006			2005
	(millions)
Discovery Producer Services LLC	$	24		$	17		$	11
Main Pass Oil Gathering Company		1			3			3
Mont Belvieu I		1			(1	)		(1	)
Sycamore Gas System General Partnership		(1	)		(1	)		(1	)
Tri-States NGL Pipeline, LLC		1			1			1
Black Lake Pipe Line Company		1			—			—
TEPPCO Partners, L.P.		—			—			8
Other unconsolidated affiliates		2			1			1

Total equity in earnings of unconsolidated affiliates	$	29		$	20		$	22

F-26

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

The following summarizes combined financial information of unconsolidated affiliates:


	For the Years Ended December 31,
	2007		2006		2005
	(millions)
Income Statement:
Operating revenues	$	354	$	322	$	328
Operating expenses	$	297	$	287	$	312
Net income	$	61	$	42	$	18


	December 31,
	2007			2006
	(millions)
Balance sheet:
Current assets	$	123		$	115
Non-current assets		638			724
Current liabilities		(49	)		(61	)
Non-current liabilities		(19	)		(7	)

Net assets	$	693		$	771

8. Estimated Fair Value of Financial Instruments

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


	December 31, 2007						December 31, 2006
	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
	(millions)
Short-term investments	$	9		$	9		$	437	$	437
Restricted investments	$	101		$	101		$	102	$	102
Accounts receivable	$	1,688		$	1,688		$	1,272	$	1,272
Accounts payable	$	1,675		$	1,675		$	1,624	$	1,624
Net unrealized (losses) and gains on mark-to-market and hedging instruments	$	(97	)	$	(97	)	$	22	$	22
Long-term debt	$	2,930		$	3,030		$	2,115	$	2,258

The fair value of short-term investments, 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.

F-27

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

9. Asset Retirement Obligations

Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets:


	December 31,
	2007			2006
	(millions)
Balance, beginning of period	$	52		$	50
Accretion expense		4			3
Liabilities incurred		4			—
Liabilities settled		—			(1	)
Other		(1	)		—

Balance, end of period	$	59		$	52

F-28

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

10. Financing

Long-term debt was as follows:


	December 31,
	2007			2006
	(millions)
Debt securities:
Issued August 2000, interest at 7.875% payable semiannually, due August 2010	$	800		$	800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011		250			250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015		200			200
Issued August 2000, interest at 8.125% payable semiannually, due August 2030		300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036		300			300
Issued September 2007, interest at 6.750% payable semiannually, due September 2037		450			—
DCP Partners’ credit facility revolver, weighted-average interest rate of 5.47% and 5.86%, respectively, due June 2012(a)		530			168
DCP Partners’ credit facility term loan, interest rate of 5.05% and 5.47%, respectively, due June 2012		100			100
Fair value adjustments related to interest rate swap fair value hedges(b)		8			4
Unamortized discount		(8	)		(7	)

Long-term debt	$	2,930		$	2,115

(a)	$425 million of debt has been swapped to a fixed rate obligation.

(b)	$100 million of debt has been swapped to a floating rate obligation.

Debt Securities—In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or the 6.75% Notes, for proceeds of approximately $444 million, net of related offering costs. The 6.75% Notes mature and become due and payable on September 15, 2037. We will pay interest semiannually on March 15 and September 15 of each year, commencing March 15, 2008. The proceeds of this offering were used to pay off the 364-Day Bridge Loan described below.

In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million, net of related offering costs. The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007.

In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015, or 5.375% Notes, for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We pay interest semiannually on April 15 and October 15 of each year, commencing April 15, 2006. The proceeds from this offering were used to repay the August 2005 term loan facility discussed below.

In August 2005, we repaid the $600 million 7.5% Notes that were due on August 16, 2005. We repaid a portion of this debt with available cash and proceeds from the issuance of commercial paper, and refinanced a portion of this debt with the August 2005 term loan facility discussed below.

The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.

F-29

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Credit Facilities with Financial Institutions—We have a $450 million revolving credit facility, or the Facility, which is used to support our commercial paper program, and for working capital and other general corporate purposes. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity to April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.23% per year for the initial 50% usage or LIBOR plus 0.28% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.07% based on our credit rating on the drawn and undrawn portions. The Facility may be used for letters of credit. As of December 31, 2007 and 2006, there were no borrowings or commercial paper outstanding, and there were approximately $5 million in letters of credit outstanding for both periods.

In August 2005, we entered into a credit agreement, or the Term Loan Facility, where we made a one-time request to borrow $200 million in the form of a term loan. We used this Term Loan Facility to repay a portion of our $600 million 7.5% Notes that matured on August 16, 2005. The Term Loan Facility was repaid in October 2005 with proceeds from the 5.375% Notes.

On June 21, 2007, DCP Partners entered into the Amended and Restated Credit Agreement, or DCP Partners’ Amended Credit Agreement, that replaced their existing credit agreement, or DCP Partners’ Credit Agreement, which consists of a $600 million revolving credit facility and a $250 million term loan facility. At December 31, 2007 and 2006, DCP Partners had less than $1 million of letters of credit outstanding. Outstanding balances under the term loan facility are fully collateralized by investments in high-grade securities, which are classified as restricted investments in the accompanying consolidated balance sheet as of December 31, 2007 and December 31, 2006.

Under DCP Partners’ 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 the leverage level or credit rating. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to; (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50%.

DCP Partners’ Amended Credit Agreement requires DCP Partners to maintain a leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, in each case as is defined by DCP Partners’ Amended Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.50 to 1.0. DCP Partners’ Amended Credit Agreement also requires DCP Partners to maintain an interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense, in each case as is defined by DCP Partners’ 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 Loans

In August 2007, we entered into a 364-day bridge loan, or the 364-Day Bridge Loan, which provided for borrowings of up to $450 million, and had terms and conditions substantially similar to those of our Facility. We borrowed $450 million to fund a portion of the acquisition of the stock of MEG, and then paid it off in September with proceeds from the issuance of the 6.75% Notes.

F-30

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

In May 2007, DCP Partners entered into a two-month bridge loan, or the Two-Month Bridge Loan, which provided for borrowings up to $100 million, and had terms and conditions substantially similar to those of DCP Partners’ Credit Agreement. In conjunction with DCP Partners entering into the Two-Month Bridge Loan, DCP Partners’ Credit Agreement was amended to provide for additional unsecured indebtedness, of an amount not to exceed $100 million, which was due and payable no later than August 9, 2007. DCP Partners used borrowings of $88 million from the Two-Month Bridge Loan to partially fund the acquisition of assets from Anadarko. The remaining $12 million available for borrowing on the Two-Month Bridge Loan was not utilized. DCP Partners used a portion of the net proceeds of a private placement of limited partner units to extinguish the $88 million outstanding on the Two-Month Bridge Loan in June 2007.

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2007:


Debt Maturities
(millions)
2010	$	800
2011		250
2012		630
Thereafter		1,258

		2,938
Unamortized discount		(8	)

Long-term debt	$	2,930

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

The impact of our derivative activity on our results of operations and financial position is summarized below:


	For the Years Ended December 31,
	2007			2006			2005
	(millions)
Commodity derivative instruments:
Gains reclassified into earnings	$	1		$	4		$	—
Commodity derivative activity:
Unrealized (losses) gains from derivative activity	$	(102	)	$	6		$	(6	)
Realized gains (losses) from derivative activity	$	59		$	71		$	(9	)
Interest rate derivative instruments:
Losses reclassified into earnings	$	(1	)	$	(1	)	$	(1	)


	December 31,
	2007			2006
	(millions)
Commodity derivative instruments:
Net deferred (losses) gains in AOCI	$	(1	)	$	3
Interest rate derivative instruments:
Net deferred losses in AOCI	$	(10	)	$	(7	)
Interest rate fair value hedges:
Unrealized gains	$	8		$	4

F-31

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

For the years ended December 31, 2007 and 2006, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Commodity Price Risk—Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process 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.

Energy Trading (Market) Risk—Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

Interest Rate Risk—We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

Credit Risk—Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

As of December 31, 2007, we held deposits, of $57 million included in other current liabilities, and letters of credit, of $97 million, from counterparties to secure their future performance of financial or physical contracts. We had deposits with counterparties of $45 million, included in other current assets, of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties publicly disclose credit ratings, which may impact the amounts of collateral requirements.

F-32

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

Commodity Derivative Activity—Our operations of gathering, processing, and transporting natural gas, and the related operations of transporting and marketing of NGL create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGL, natural gas and crude oil.

We manage our commodity derivative activities in accordance with our risk management policy, which limits exposure to market risk and requires regular reporting to management of potential financial exposure.

Commodity Cash Flow Protection Activities—DCP Partners uses NGL, natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGL, natural gas and condensate. Prior to July 1, 2007, the effective portion of the change in fair value of a derivative designated as a cash flow hedge was accumulated in AOCI. During the period in which the hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were reclassified to the consolidated statements of operations and comprehensive income in the same accounts as the item being hedged.

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. Therefore, we are using the mark-to-market method of accounting for all commodity derivative instruments. As a result, the remaining net loss deferred in AOCI will be reclassified to sales of natural gas and petroleum products through December 2011, as the hedged transactions impact earnings. Deferred net losses of less than $1 million are expected to be reclassified into earnings during the next 12 months. Subsequent to July 1, 2007, the changes in fair value of these financial derivatives are included in trading and marketing gains and losses in the consolidated statements of operations and comprehensive income.

As of December 31, 2007, DCP Partners has mitigated a portion of our expected natural gas, NGL and condensate commodity price risk associated with the equity volumes from their gathering and processing operations through 2013 with natural gas, NGL and crude oil derivatives.

Commodity Fair Value Hedges—Historically, we used fair value hedges to mitigate risk to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our cash flow exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

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 Derivatives—Trading and Marketing—Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables

F-33

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.

Interest Rate Cash Flow Hedges—DCP Partners mitigates a portion of their interest rate risk with interest rate swaps, which reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swaps convert the interest rate associated with an aggregate of $425 million of the variable rate exposure to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the consolidated balance sheets. As of December 31, 2007, $2 million of deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings. The agreements reprice prospectively approximately every 90 days. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 3.97% to 5.19%, and receive interest payments based on the three-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of the agreements.

Interest Rate Fair Value Hedges—In August 2003, we entered into two interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions that permit the assumption of no ineffectiveness. As such, for the life of the swaps no ineffectiveness will be recognized.

12. Non-Controlling Interest

Non-controlling interest represents the ownership interests of third-party entities in net assets of various equity method investments in consolidated affiliates, including ownership interest of DCP Partners’ public unitholders in net assets of DCP Partners through DCP Partners’ publicly traded common units, and in net assets of DCP East Texas Holdings, LLC, of which DCP Partners acquired a 25% equity interest in July 2007 as well as Collbran Valley Gas Gathering, which was acquired in conjunction with the MEG acquisition in August 2007. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party and affiliate investors’ interest in our consolidated balance sheet amounts shown as non-controlling interest. Distributions to and contributions from non-controlling interests represent cash payments and cash contributions, respectively, from such third-party and affiliate investors.

F-34

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

13. Stock-Based Compensation

We recorded stock-based compensation expense as follows, the components of which are further described below:


	For the Years Ended December 31,
	2007		2006		2005
	(millions)
DCP Midstream, LLC Long-Term Incentive Plan (2006 Plan)	$	4	$	1	$	—
DCP Partners’ Long-Term Incentive Plan (DCP Partners’ Plan)		2		1		—
Duke Energy 1998 Plan and Spectra Energy Long-Term Incentive Plan		1		6		5

Total	$	7	$	8	$	5


	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2007 (millions)		Estimated Forfeiture Rate		Weighted- Average Remaining Vesting (years)
DCP Midstream’s 2006 Plan:
Relative Performance Units (RPUs)	8	$	1	64	%	6
Strategic Performance Units (SPUs)	3	$	4	12%/32	%	2
Phantom Units	5	$	1	19	%	4
DCP Partners’ Phantom Units	3	$	1	12%/32	%	1
DCP Partners’ Plan:
Performance Units	3	$	1	0	%	2
Phantom Units	3	$	—	0	%	1
Duke Energy’s 1998 Plan and Spectra Energy’s 2007 LTIP Plan:
Stock Options (no activity in 2006 or 2007)	0-10	$	—	NA		—
Stock Based Performance Awards	3	$	—	0-8	%	1
Phantom Awards	1-5	$	—	4-5	%	2
Other Stock Awards	1-5	$	—	NA		—

DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan—Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPUs, Strategic Performance Units, or SPUs, and Phantom Units. The RPUs, SPUs and Phantom Units consist of a notional unit based on the value of common shares or units of ConocoPhillips, Duke Energy, Spectra Energy and DCP Partners. The weighting varies depending on when the units were granted. The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of DCP Partners’ common units. Each award provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006. All awards are subject to cliff vesting.

Relative Performance Units—The number of RPUs that will ultimately vest range from 0% to 200% of the outstanding RPUs, depending on the achievement of specified performance targets over a three year period ending in January 2009 and 2010, respectively, for units granted in 2006 and 2007. The final performance payout is determined by the compensation committee of our board of directors. After the performance period, vesting

F-35

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

occurs over five years, at the end of which the value is based on the participant’s investment elections during the deferral period. Dividend or distribution equivalent rights will be paid in cash at the end of the performance period. The following tables presents information related to RPUs:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	44,080		$	42.89

Outstanding at December 31, 2006	44,080		$	42.89
Granted	42,340		$	43.98
Forfeited	(21,237	)	$	43.55
Vested or paid in cash	(3,016	)	$	42.86

Outstanding at December 31, 2007	62,167		$	43.41	$	54.84

Expected to vest	33,041		$	43.41	$	54.84

Strategic Performance Units—The number of SPUs that will ultimately vest range from 0% to 150% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008 and 2009, respectively, for units granted in 2006 and 2007. The final performance payout is determined by the compensation committee of our board of directors. Dividend or distribution equivalent rights will be paid in cash at the end of the performance period. The following tables presents information related to SPUs:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	84,960		$	42.92

Outstanding at December 31, 2006	84,960		$	42.92
Granted	86,380		$	44.04
Forfeited	(28,305	)	$	43.51
Vested or paid in cash	(3,016	)	$	42.86

Outstanding at December 31, 2007	140,019		$	43.49	$	54.84

Expected to vest	127,432		$	43.49	$	54.84

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

F-36

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Phantom Units—Dividend or distribution equivalent rights are paid quarterly in arrears. The following table presents information related to Phantom Units:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	17,460		$	42.95

Outstanding at December 31, 2006	17,460		$	42.95
Granted	19,450		$	44.10
Forfeited	(2,930	)	$	43.42
Vested or paid in cash	(180	)	$	42.86

Outstanding at December 31, 2007	33,800		$	43.57	$	54.84

Expected to vest	29,931		$	43.57	$	54.84

DCP Partners’ Phantom Units—The distribution equivalent rights are paid quarterly in arrears. The following table presents information related to the DCP Partners’ Phantom Units:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	47,750		$	28.60

Outstanding at December 31, 2006	47,750		$	28.60
Granted	13,500		$	50.57
Forfeited	(2,000	)	$	28.60
Vested or paid in cash	(7,500	)	$	28.60

Outstanding at December 31, 2007	51,750		$	34.33	$	45.95

Expected to vest	46,080		$	34.33	$	45.95

DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan—Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, which was adopted by DCP Midstream GP, LLC, equity instruments may be granted to key employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. All awards are subject to cliff vesting, with the exception of the Phantom Units issued to the directors in conjunction with the initial public offering, which are subject to graded vesting provisions.

F-37

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Awards granted to directors are accounted for as equity-based awards and all other awards are accounted for as liability awards.

Performance Units—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 percentage payout is determined by the compensation committee of DCP Partners’ board of directors. The DERs will be paid in cash at the end of the performance period. Of the remaining Performance Units outstanding at December 31, 2007, 28,350 units are expected to vest on December 31, 2008 and 27,150 units are expected to vest on December 31, 2009. The following tables presents information related to the Performance Units:


	Units		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		$	37.29
Forfeited	(5,740	)	$	31.39

Outstanding at December 31, 2007	46,960		$	32.93	$	45.95

Expected to vest(a)	55,500		$	32.93	$	45.95

(a)	Based on our December 31, 2007 estimated achievement of specified performance targets, the number of performance units granted in 2006 that will ultimately vest is estimated at 143% of the targeted units granted.

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

Phantom Units—In conjunction with their initial public offering, in January 2006 DCP Partners awarded Phantom Units to key employees, and to directors who are not officers or employees of DCP Midstream GP, LLC, or its affiliates who perform services for DCP Partners. Of the remaining Phantom Units outstanding at December 31, 2007, 2,001 units are expected to vest on January 3, 2008 and 17,698 units are expected to vest on January 3, 2009.

In 2007, DCP Partners granted 4,500 Phantom Units pursuant to the DCP Partners’ Plan, to directors who are not officers or employees of affiliates of DCP Midstream as part of their annual director fees for 2007. Of these Phantom Units, 4,000 units vested during 2007 and 500 units are expected to vest on February 7, 2008.

The DERs are paid quarterly in arrears.

F-38

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

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	4,500		$	42.90
Forfeited	(2,333	)	$	24.05
Vested	(6,668	)	$	35.23

Outstanding at December 31, 2007	20,199		$	24.56	$	45.95

Expected to vest	20,199		$	24.56	$	45.95

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 and comprehensive income.

During the year ended December 31, 2007, 2,668 units vested and were settled in cash for less than $1 million, and 4,000 units were settled with the issuance of limited partner units.

All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash or stock upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date.

Duke Energy 1998 Plan and Spectra Energy 2007 Long-Term Incentive Plan—Under the Duke Energy 1998 Plan, or the 1998 Plan, Duke Energy granted certain of our key employees stock options, stock-based performance awards, phantom stock awards and other stock awards to be settled in shares of Duke Energy’s common stock, or the Stock-Based Awards. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we began accounting for these awards using the fair value method. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.

In connection with the Spectra spin, one replacement Duke Energy Stock-Based Award and one-half Spectra Energy Stock-Based Award were distributed to each holder of Duke Energy Stock-Based Awards for each award held at the time of the Spectra spin. Substantially all converted Stock-Based Awards are subject to the terms and conditions applicable to the original Duke Energy Stock-Based Awards. The Spectra Energy Stock-Based Awards resulting from the conversion are considered to have been issued under the Spectra Energy 2007 Long-Term Incentive Plan, or the Spectra Energy 2007 LTIP.

The Spectra Energy 2007 LTIP provides for the granting of stock options, restricted stock awards and units, unrestricted stock awards and units, and other equity-based awards, to employees and other key individuals who

F-39

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

perform services for Spectra Energy. A maximum of 30 million shares of common stock may be awarded under the Spectra Energy 2007 LTIP. Options granted under the Spectra Energy 2007 LTIP are issued with exercise prices equal to the fair market value of Spectra Energy common stock on the grant date, have ten year terms, and vest immediately or over terms not to exceed five years. Compensation expense related to stock options is recognized over the requisite service period. The requisite service period for stock options is the same as the vesting period, with the exception of retirement eligible employees, who have shorter requisite service periods ending when the employees become retirement eligible. Restricted, performance and phantom stock awards granted under the Spectra Energy 2007 LTIP typically become 100% vested on the three-year anniversary of the grant date. The fair value of the awards granted is measured based on the fair market value of the shares on the date of grant, and the related compensation expense is recognized over the requisite service period which is the same as the vesting period.

Stock Options—Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Effective July 1, 2005, these options were accounted using the fair value method. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.

The following table shows information regarding options to purchase Duke Energy’s common stock granted to our employees, reflecting shares outstanding as impacted by the conversion.


	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Life (years)	Aggregate Intrinsic Value (millions)
Outstanding at December 31, 2005	2,592,567		$	29.46	5.2
Exercised	(367,088	)	$	21.15
Forfeited	(124,417	)	$	29.96
Effect of conversion	(258,058	)

Outstanding at December 31, 2006	1,843,004		$	17.85	4.1
Exercised	(21,960	)	$	13.89
Forfeited	(5,088	)	$	22.90

Outstanding at December 31, 2007	1,815,956		$	17.89	3.2	$	7

Exercisable at December 31, 2007	1,815,956		$	17.89	3.2	$	7

The total intrinsic value of options exercised during the years ended December 31, 2007 and 2006, was less than $1 million and approximately $3 million, respectively.

F-40

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

The following table shows information regarding options to purchase Spectra Energy’s common stock granted to our employees, reflecting shares outstanding as impacted by the conversion.


	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Life (years)	Aggregate Intrinsic Value (millions)
Outstanding at December 31, 2005	—		$	—
Effect of conversion	1,066,595

Outstanding at December 31, 2006	1,066,595		$	26.43	4.1
Exercised	(73,920	)	$	17.84
Forfeited	(55,427	)	$	31.78

Outstanding at December 31, 2007	937,248		$	26.80	3.2	$	3

Exercisable at December 31, 2007	937,248		$	26.80	3.2	$	3

The total intrinsic value of options exercised during the years ended December 31, 2007 was approximately $1 million.

Stock-Based Performance Awards—There were no stock-based performance awards granted during the years ended December 31, 2007 and 2006.

The following tables summarize information about stock-based performance awards activity, reflecting shares outstanding as impacted by the conversion:


Duke Energy 1998 Plan	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	342,453		$	23.88
Forfeited	(40,835	)	$	23.85
Effect of conversion	(128,213	)

Outstanding at December 31, 2006	173,405		$	15.58
Forfeited	(40	)	$	15.38

Outstanding at December 31, 2007	173,365		$	15.58	$	20.17

Expected to vest	173,325		$	15.58	$	20.17

Spectra Energy 2007 LTIP	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Effect of conversion	184,083

Outstanding at December 31, 2006	184,083		$	20.93
Vested	(83,309	)	$	18.30
Forfeited	(14,091	)	$	20.42

Outstanding at December 31, 2007	86,683		$	23.54	$	25.82

Expected to vest	80,048		$	23.54	$	25.82

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

The total fair value of the performance stock awards that vested during the year ended December 31, 2007 was approximately $2 million. No awards were granted, vested or canceled during the years ended December 31, 2007 and 2006.

Phantom Stock Awards—There were no phantom stock awards granted during the years ended December 31, 2007 and 2006.

The following tables summarize information about phantom stock awards activity, reflecting shares outstanding as impacted by the conversion:


Duke Energy 1998 Plan	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	241,216		$	24.22
Vested	(54,150	)	$	23.90
Forfeited	(22,378	)	$	24.29
Effect of conversion	(52,664	)

Outstanding at December 31, 2006	112,024		$	15.59
Vested	(29,190	)	$	15.54
Forfeited	(5,624	)	$	15.38

Outstanding at December 31, 2007	77,210		$	15.62	$	20.17

Expected to vest	73,960		$	15.62	$	20.17


Spectra Energy 2007 LTIP	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Effect of conversion	104,171

Outstanding at December 31, 2006	104,171		$	21.31
Vested	(59,258	)	$	19.66
Forfeited	(6,308	)	$	22.81

Outstanding at December 31, 2007	38,605		$	23.60	$	25.82

Expected to vest	36,487		$	23.60	$	25.82

The total fair value of the phantom stock awards that vested during the years ended December 31, 2007 and 2006 was approximately $2 million for both periods. No awards were granted or canceled during the years ended December 31, 2007 and 2006.

Other Stock Awards—There were no other stock awards granted during the years ended December 31, 2007 and 2006.

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

The following tables summarize information about other stock awards activity, reflecting shares outstanding as impacted by the conversion:


Duke Energy 1998 Plan	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	45,400		$	21.73
Vested	(10,600	)	$	21.73
Forfeited	(13,200	)	$	21.73

Outstanding at December 31, 2006	21,600		$	12.38
Vested	(21,600	)	$	12.38
Forfeited	—		$	—

Outstanding at December 31, 2007	—		$	—	$	—

Expected to vest	—		$	—	$	—


Spectra Energy 2007 LTIP	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Effect of conversion	10,800

Outstanding at December 31, 2006	10,800		$	18.71
Vested	(10,800	)	$	18.71
Forfeited	—		$	—

Outstanding at December 31, 2007	—		$	—	$	—

Expected to vest	—		$	—	$	—

The total fair value of the other stock awards that vested during the years ended December 31, 2007 and 2006 was not significant. No awards were granted or canceled during the years ended December 31, 2007 and 2006.

14. Benefits

All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings to the retirement plan, based on years of service. Additionally, we match employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During 2007 we expensed plan contributions of $17 million and during 2006 and 2005 we expensed plan contributions of $15 million in both periods.

We offer certain eligible executives the opportunity to participate in DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.

15. Income Taxes

We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state and local taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.

In May 2006, the State of Texas enacted a margin-based franchise tax law that replaced the existing franchise tax, commonly referred to as the Texas margin tax. The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. As a result of the change in Texas franchise law, our status in the state of Texas changed from non-taxable to taxable. Since the Texas margin tax is considered an income tax, in the second quarter of 2006 we recorded a non-current deferred tax liability of $18 million. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year. Accordingly, we recorded current tax expense for the Texas margin tax, beginning in 2007.

Income tax expense consists of the following:


	For the Years Ended December 31,
	2007			2006		2005
	(millions)
Current:
Federal	$	5		$	5	$	9
State		11			1		2
Deferred:
Federal		(4	)		—		—
State		(1	)		17		(2	)

Total income tax expense	$	11		$	23	$	9

Temporary differences for our federal deferred tax assets of $7 million primarily relate to basis differences between property, plant and equipment, and investments in consolidated affiliates. Temporary differences for our state deferred tax liabilities of $16 million primarily relate to basis differences between property, plant and equipment.

Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

16. Commitments and Contingent Liabilities

Litigation—The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. 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 currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.

In October 2007, we settled a lawsuit alleging migration of acid gas from a storage formation into a third party producing formation. Pending regulatory approval, we will obtain the rights to the producing formation. This matter did not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.

General Insurance—Effective August 2006, Midstream’s insurance coverage is carried with an affiliate of ConocoPhillips and third party insurers. Prior to August 2006, Midstream carried a portion of their insurance coverage with an affiliate of Duke Energy Corporation. Midstream’s insurance coverage includes: (1) general liability insurance covering third party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of all real and personal property and includes business interruption/extra expense; and (6) directors and officers insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. Also, during the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages were covered by our insurance, subject to applicable deductibles. The financial impact of hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables and business interruption recoveries related to these hurricanes are detailed in Note 3.

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

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

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, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at six of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions beginning January 2001, and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. 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.

Other Commitments and Contingencies—In June 2007, DCP Partners entered into a private placement agreement with a group of institutional investors for $130 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $129 million, net of offering costs. In August 2007, DCP Partners issued 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate. In January 2008, DCP Partners’ registration statement on Form S-3 to register the common limited partner units represented in the private placement agreements was declared effective by the Securities and Exchange Commission.

We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $41 million, $37 million and $36 million in 2007, 2006 and 2005, 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:


Minimum Rental Payments
(millions)
2008	$	24
2009		19
2010		18
2011		17
2012		15
Thereafter		31

Total gross payments		124
Sublease receipts		(1	)

Total net payments	$	123

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

17. Guarantees and Indemnifications

We have signed a corporate guaranty, pursuant to which we are the guarantor of a maximum of approximately $1 million and $10 million of construction obligations as of December 31, 2007 and 2006, respectively. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2008. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.

We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities.

18. Supplementary Cash Flow Information


	December 31,
	2007		2006		2005
	(millions)
Cash paid for interest:
Cash paid for interest expense, net of capitalized interest	$	159	$	141	$	163
Cash paid for income taxes	$	11	$	10	$	13
Non-cash investing and financing activities:
Non-cash additions of property, plant and equipment	$	8	$	10	$	13
Distributions payable to members	$	123	$	127	$	185

19. Subsequent Events

On January 24, 2008, DCP Partners announced the declaration of a cash distribution of $0.57 per unit that was paid on February 14, 2008 to unitholders of record on February 7, 2008.

In January 2008, we received a distribution from Discovery of $11 million.

In February 2008, 50% of our subordinated units in DCP Partners, or 3,571,428 subordinated units, were converted to common units in accordance with the early termination provision in DCP Partners’ partnership agreement.

Subsequent to December 31, 2007, DCP Partners executed a series of derivative instruments to mitigate a portion of its anticipated commodity exposure. DCP Partners entered into natural gas swap contracts for 2,000 MMBtu/d at $7.80/MMBtu, for a term from July through December 2008, and DCP Partners entered into crude oil swap contracts, each for 225 Bbls/d at an average of $87.93/Bbl, for terms ranging from July 2008 through December 2012.

On March 17, 2008, DCP Partners closed an offering of 4,250,000 of its common units representing limited partner interests at $32.44 per unit.

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DCP MIDSTREAM, LLC

SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND

RESERVES FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005


	Balance at Beginning of Period		Charged to Consolidated Statements of Operations		Charged to Other Accounts (b)			Deductions (c)			Balance at End of Period
	(Millions)
December 31, 2007
Allowance for doubtful accounts	$	3	$	2	$	1		$	(1	)	$	5
Environmental		12		2		2			(4	)		12
Litigation		9		9		—			(3	)		15
Other (a)		4		—		—			(1	)		3

	$	28	$	13	$	3		$	(9	)	$	35

December 31, 2006
Allowance for doubtful accounts	$	4	$	—	$	—		$	(1	)	$	3
Environmental		13		3		—			(4	)		12
Litigation		5		6		—			(2	)		9
Other (a)		6		—		—			(2	)		4

	$	28	$	9	$	—		$	(9	)	$	28

December 31, 2005
Allowance for doubtful accounts	$	4	$	1	$	—		$	(1	)	$	4
Environmental		17		5		—			(9	)		13
Litigation		8		1		2			(6	)		5
Other (a)		8		11		(2	)		(11	)		6

	$	37	$	18	$	—		$	(27	)	$	28

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

(b)	Consists of purchase accounting adjustments for the Momentum Energy Group, Inc. acquisition in 2007 and other contingency and litigation reserves reclassified between accounts in 2005.

(c)	Principally consists of cash payments, collections, reserve reversals and liabilities settled.

F-48