Edgar Filing: Spectra Energy Corp.

Form 10-K/A for fiscal year ended December 31, 2009

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, 2009 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 June 30, 2009: $10,900,000,000

Number of shares of Common Stock, $0.001 par value, outstanding at February 12, 2010: 647,483,298

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K of Spectra Energy Corp for the fiscal year ended December 31, 2009 is being filed for the purpose of providing separate audited financial statements of DCP Midstream, LLC in accordance with Rule 3-09 of Regulation S-X. These audited financial statements, which were not available prior to the filing our 2009 Form 10-K, are included in Item 15. Exhibits, Financial Statement Schedules. This amendment does not update or modify in any way the consolidated results of operations, financial position, cash flows or other disclosures in Spectra Energy Corp’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, and does not reflect events occurring after the original filing date of our Form 10-K of February 25, 2010.

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements.

The following financial statements were filed as part of Spectra Energy Corp’s Form 10-K filed February 25, 2010:

Spectra Energy Corp:

Report of Independent Registered Accounting Firm

Consolidated Statements of Operations

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Equity and Comprehensive Income

Notes to Consolidated Financial Statements

The following financial statements are included herein:

DCP Midstream, LLC:

Independent Auditors’ Report

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Comprehensive Income

Consolidated Statements of Cash Flows

Consolidated Statements of Changes in Equity

Notes to Consolidated Financial Statements

(a)(2) Financial Statement Schedules.

The following financial statement schedule was filed as part of Spectra Energy Corp’s Form 10-K filed February 25, 2010:

Spectra Energy Corp:

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves

All other schedules are omitted because they are not required or because the required information is included in the respective Consolidated Financial Statements or Notes thereto.

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

SIGNATURES

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 11, 2010				/s/ Sabra L. Harrington
				Sabra L. Harrington
				Vice President and Controller

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		F-3

Consolidated Statements of Comprehensive Income		F-4

Consolidated Statements of Cash Flows		F-5

Consolidated Statements of Changes in Equity		F-6

Notes to Consolidated Financial Statements		F-7


		Deloitte & Touche LLP
		Suite 3600
		555 Seventeenth Street
		Denver, CO 80202-3942
		USA

		Tel: +1 303 292 5400
		Fax: +1 303 312 4000
		www.deloitte.com

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 (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements 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 the Company as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company adopted the amended provisions of ASC 810, Consolidation, as it pertains to noncontrolling interests, and as a result retrospectively adjusted its 2008 and 2007 consolidated financial statements.

/s/ Deloitte & Touche LLP

February 26, 2010

Member of

Deloitte Touche Tohmatsu

F-1

DCP MIDSTREAM, LLC

CONSOLIDATED BALANCE SHEETS

(millions)


	December 31, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	264		$	133
Accounts receivable:
Customers, net of allowance for doubtful accounts of $3 million and $6 million, respectively		898			735
Affiliates		255			221
Other		35			44
Inventories		83			43
Unrealized gains on derivative instruments		259			419
Other		15			70

Total current assets		1,809			1,665

Property, plant and equipment, net		4,922			4,836
Restricted investments		10			60
Investments in unconsolidated affiliates		175			179
Intangible assets, net		313			319
Goodwill		662			658
Unrealized gains on derivative instruments		41			119
Other long-term assets		60			46

Total assets	$	7,992		$	7,882

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,003		$	888
Affiliates		90			48
Other		38			46
Short-term borrowings		3			100
Current maturities of long-term debt		800			—
Distributions payable to members		71			—
Unrealized losses on derivative instruments		229			398
Accrued interest payable		70			59
Accrued taxes		47			44
Other		183			188

Total current liabilities		2,534			1,771

Deferred income taxes		104			90
Long-term debt		2,841			3,602
Unrealized losses on derivative instruments		78			81
Other long-term liabilities		117			376
Commitments and contingent liabilities
Equity:
Members’ interest		2,020			1,667
Accumulated other comprehensive loss		(17	)		(17	)

Total members’ equity		2,003			1,650
Noncontrolling interest		315			312

Total equity		2,318			1,962

Total liabilities and equity	$	7,992		$	7,882

See Notes to Consolidated Financial Statements.

F-2

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(millions)


	Year Ended December 31,
	2009			2008			2007
Operating revenues:
Sales of natural gas and petroleum products	$	6,080		$	12,456		$	10,009
Sales of natural gas and petroleum products to affiliates		2,140			3,507			2,884
Transportation, storage and processing		327			334			304
Trading and marketing gains (losses), net		50			101			(43	)

Total operating revenues		8,597			16,398			13,154

Operating costs and expenses:
Purchases of natural gas and petroleum products		6,213			12,489			10,097
Purchases of natural gas and petroleum products from affiliates		650			1,045			781
Operating and maintenance		520			586			510
Depreciation and amortization		405			365			316
General and administrative		236			234			258
Loss (gain) on sale of assets		2			(15	)		(3	)

Total operating costs and expenses		8,026			14,704			11,959

Operating income		571			1,694			1,195
Equity in earnings of unconsolidated affiliates		24			20			29
Interest income		1			12			16
Interest expense		(255	)		(210	)		(170	)

Income before income taxes		341			1,516			1,070
Income tax (expense) benefit		(18	)		3			(11	)

Net income		323			1,519			1,059
Net loss (income) attributable to noncontrolling interests		16			(88	)		15

Net income attributable to members’ interests	$	339		$	1,431		$	1,074

See Notes to Consolidated Financial Statements.

F-3

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(millions)


	Year Ended December 31,
	2009			2008			2007
Net income	$	323		$	1,519		$	1,059

Other comprehensive income (loss):
Net unrealized losses on cash flow hedges		(14	)		(33	)		(19	)
Reclassification of cash flow hedge losses into earnings		22			9			(3	)

Total other comprehensive income (loss)		8			(24	)		(22	)

Total comprehensive income		331			1,495			1,037
Total comprehensive loss (income) attributable to noncontrolling interests		8			(70	)		29

Total comprehensive income attributable to members’ interests	$	339		$	1,425		$	1,066

See Notes to Consolidated Financial Statements.

F-4

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(millions)


	Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities:
Net income	$	323		$	1,519		$	1,059
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (gain) on sale of assets		2			(15	)		(3	)
Depreciation and amortization		405			365			316
Equity in earnings of unconsolidated affiliates, net of distributions		11			24			3
Deferred income tax expense (benefit)		14			(13	)		(1	)
Other, net		3			42			11
Changes in operating assets and liabilities which (used) provided cash:
Accounts receivable		(189	)		715			(398	)
Inventories		(43	)		74			(30	)
Net unrealized losses (gains) on derivative instruments		74			(181	)		99
Accounts payable		145			(693	)		33
Accrued interest payable		11			3			9
Other		81			(52	)		50

Net cash provided by operating activities		837			1,788			1,148

Cash flows from investing activities:
Capital expenditures		(471	)		(557	)		(409	)
Acquisitions, net of cash acquired		(45	)		(214	)		(795	)
Investments in unconsolidated affiliates		(7	)		(7	)		(4	)
Purchases of available-for-sale securities		(1	)		(1,157	)		(15,812	)
Proceeds from sales of available-for-sale securities		51			1,207			16,243
Proceeds from sale of assets		5			41			1
Other		—			(2	)		2

Net cash used in investing activities		(468	)		(689	)		(774	)

Cash flows from financing activities:
Payment of dividends and distributions to members		(202	)		(1,861	)		(1,364	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		70			132			229
Proceeds from debt		680			2,230			1,477
Payment of debt		(742	)		(1,494	)		(667	)
Payment of debt acquired		—			—			(20	)
Distributions paid to noncontrolling interests		(55	)		(48	)		(25	)
Contributions from noncontrolling interests		14			6			3
Deferred financing costs		(3	)		(2	)		(4	)

Net cash used in financing activities		(238	)		(1,037	)		(371	)

Net change in cash and cash equivalents		131			62			3
Cash and cash equivalents, beginning of period		133			71			68

Cash and cash equivalents, end of period	$	264		$	133		$	71

See Notes to Consolidated Financial Statements.

F-5

DCP MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(millions)


	Members’ Equity
	Members’ Interest			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interest			Total Equity
Balance, January 1, 2007	$	2,260		$	(3	)	$	71		$	2,328
Contributions		—			—			3			3
Dividends and distributions		(1,360	)		—			(25	)		(1,385	)
Purchase of business		—			—			23			23
Issuance of equity securities of a subsidiary		—			—			150			150

Comprehensive income (loss):
Net income (loss)		1,074			—			(15	)		1,059
Net unrealized losses on cash flow hedges		—			(7	)		(12	)		(19	)
Reclassifications of cash flow hedge losses into earnings		—			(1	)		(2	)		(3	)

Total comprehensive income (loss)		1,074			(8	)		(29	)		1,037

Balance, December 31, 2007		1,974			(11	)		193			2,156
Contributions		—			—			6			6
Dividends and distributions		(1,738	)		—			(48	)		(1,786	)
Purchase of business		—			—			2			2
Issuance of equity securities of a subsidiary		—			—			89			89

Comprehensive income (loss):
Net income		1,431			—			88			1,519
Net unrealized losses on cash flow hedges		—			(11	)		(22	)		(33	)
Reclassifications of cash flow hedge losses into earnings		—			5			4			9

Total comprehensive income (loss)		1,431			(6	)		70			1,495

Balance, December 31, 2008		1,667			(17	)		312			1,962
Contributions		—			—			14			14
Dividends and distributions		(274	)		—			(55	)		(329	)
Issuance of equity securities of a subsidiary		18			—			52			70
Reclassification of deferred liability		270			—			—			270

Comprehensive income (loss):
Net income (loss)		339			—			(16	)		323
Net unrealized losses on cash flow hedges		—			(6	)		(8	)		(14	)
Reclassifications of cash flow hedge losses into earnings		—			6			16			22

Total comprehensive income (loss)		339			—			(8	)		331

Balance, December 31, 2009	$	2,020		$	(17	)	$	315		$	2,318

See Notes to Consolidated Financial Statements.

F-6

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2009, 2008 and 2007

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 gathering, processing, compressing, transporting and storing of natural gas, and fractionating, transporting, gathering, treating, processing and storing of natural gas liquids, or NGLs, and/or condensate as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs.

DCP Midstream Partners, LP, or DCP Partners, is a master limited partnership, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. At December 31, 2009 and 2008, we owned an approximately 34% and 29% limited partner interest, respectively, and an approximately 1% general partner interest in DCP Partners for both periods as well as incentive distribution rights that entitle us to receive an increasing share of available cash as pre-defined distribution targets are achieved. As the general partner of DCP Partners, we have responsibility for its operations. We exercise control over DCP Partners and we account for it as a consolidated subsidiary.

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 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. 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.

We adopted Financial Accounting Standards Board, or FASB, Accounting Standards Codification 810, or ASC 810, effective January 1, 2009, which required us to retrospectively recast our consolidated financial statements for all periods presented. As a result of adoption, we have reclassified our noncontrolling interest on our consolidated balance sheets, from a component of liabilities to a component of equity and have also reclassified net (income) loss attributable to noncontrolling interest on our consolidated statements of operations, to below net income for all periods presented. Furthermore, we have displayed the portion of other comprehensive income that is attributable to noncontrolling interest within our consolidated statements of comprehensive income. We also added a rollforward of the noncontrolling interest within our consolidated statements of changes in equity and have combined the members’ interest and retained earnings columns within the rollforward. We will be presenting the rollforward of members’ equity on a quarterly basis. Additionally, in the first quarter of 2009 we reclassified $270 million deferred liabilities relating to the sale of common equity by a subsidiary from long-term liabilities to members’ interest within our consolidated balance sheets.

Certain amounts in the prior year’s consolidated financial statements have been reclassified to the current year presentation.

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

F-7

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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 include 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 and money market instruments. 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 or loss, or AOCI. No such gains or losses were deferred in AOCI at December 31, 2009 or 2008. Restricted investments consist of collateral for DCP Partners’ term loan. The costs, including accrued interest on investments, approximate fair value due to the short-term, highly liquid nature of the securities held by us; interest rates are re-set on a daily, weekly or monthly basis.

Allowance for Doubtful Accounts—Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.

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—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. The remaining non-trading derivatives (which are related to asset based activity) for which hedge accounting or the normal purchase or normal sale exception are not elected, are recorded at fair value on the balance sheet as unrealized gains or unrealized losses on derivative instruments, with changes in the fair value recognized in the consolidated statements of operations are as follows:


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

Non-Trading Derivatives:

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

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

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

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

F-8

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

a	Mark-to-market—An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in 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 derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the 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 in the same category as the related hedged item.

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

Cash Flow and Fair Value Hedges—For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the 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 derivative 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. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same accounts as the item being hedged. 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.

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 internally developed pricing models developed primarily from historical and expected relationships with quoted market prices.

F-9

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

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.

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 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 considered to be permanently 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 customer contracts and related relationships, including commodity purchase, transportation and processing contracts. These intangible assets are amortized on a straight-line basis over the term of the contract or anticipated relationship, ranging from one to 25 years. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

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 when we believe events or changes in circumstances indicate we may not be able to recover the carrying value of the reporting unit. 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

F-10

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. 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.

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 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. 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.

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 long-term assets.

Distributions—Under the terms of the Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or 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 value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate

F-11

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. During the years ended December 31, 2009, 2008 and 2007, we paid tax distributions of $92 million, $721 million and $497 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 periodic dividends to be paid to Spectra Energy and ConocoPhillips, by considering net income attributable to members’ interests, 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, 2009, 2008 and 2007, we paid dividends of $110 million, $1,140 million and $867 million, respectively, to the members, allocated in accordance with their respective ownership percentages.

DCP Partners considers the payment of a quarterly distribution to the holders of its common 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 consists of common units, and included subordinated units and Class D units until they were converted to common units in February 2009 and August 2009, respectively. During years ended December 31, 2009, 2008 and 2007, DCP Partners paid distributions of $50 million, $45 million and $25 million, respectively, to its public unitholders. In addition to our general partner and limited partnership interests in DCP Partners, we hold incentive distribution rights, which entitle us to receive an increasing share of available cash as pre-defined distribution targets are achieved.

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 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 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 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 percent-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

F-12

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

and/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percent-of-proceeds/index arrangements relate directly with the price of natural gas and/or NGLs.

•

Keep-whole arrangements and wellhead purchase arrangements—Under the terms of a keep-whole processing contract, we gather 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 natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase 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, credit metrics, liquidity 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 cash is collected.

We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. 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 as trading and marketing gains and losses. These activities include mark-to-market gains and losses on energy trading contracts, and the settlement of financial or physical 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, 2009, 2008 and 2007.

F-13

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable-other or accounts payable-other 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, 2009 and 2008 were imbalances totaling $28 million and $44 million, respectively. Included in the consolidated balance sheets as accounts payable—other, as of December 31, 2009 and 2008 were imbalances totaling $38 million and $46 million, respectively.

Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in each of the past three years. Total revenues from ConocoPhillips, including its 50% owned equity method investment, Chevron Phillips Chemical Company LLC, or CP Chem, a 50% equity investment of ConocoPhillips, totaled $2,121 million, $3,430 million and $2,804 million during 2009, 2008 and 2007, 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, 2009 and 2008, included in the consolidated balance sheets, totaled $5 million and $7 million, respectively, recorded as other current liabilities, and $11 million and $11 million, respectively, recorded as other long-term liabilities.

Equity-Based Compensation—Equity classified equity-based compensation cost is measured at fair value, based on the closing unit price at grant date, and is recognized as expense over the vesting period. Liability classified equity-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.

Accounting for Sales of Units by a Subsidiary—We account for sales of units by a subsidiary by recording an increase in members’ interest equal to the amount of net proceeds received in excess of the carrying value of the units sold. Prior to January 1, 2009, we accounted for sales of units by a subsidiary by recording a deferred item on the sale of common equity of a subsidiary equal to the amount of net proceeds received in excess of the carrying value of the units sold. The remaining net proceeds is recorded as an increase to noncontrolling interest. Prior to the first quarter of 2009, DCP Partners had two classes of units outstanding, consisting of subordinated and limited partner units, which required us to record a deferred liability of $270 million within our consolidated balance sheets. During the first quarter of 2009 the subordination period ended and these units were converted into limited partner units and we reclassified these deferred liabilities from long-term liabilities to members’ interest within our consolidated balance sheets.

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.

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.

F-14

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Recent Accounting Pronouncements—On July 1, 2009, the FASB ASC became the source for authoritative United States Generally Accepted Accounting Principles, or GAAP, as noted in the discussion of Accounting Standards Update, or ASU, 2009-01 below. During the second half of 2009, the FASB issued several ASUs. The following outlines the ASUs that are applicable to us and may have an impact on our consolidated financial statements and related disclosures:

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

ASU 2010-02 “Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification,” or ASU 2010-02—In January 2010, the FASB issued ASU 2010-02 which amended ASC topic 810-10 “Consolidation—Overall.” ASU 2010-02 clarifies guidance on the scope of the decrease in ownership provisions of ASC 810-10 and expands the disclosures about the deconsolidation of a subsidiary and the derecognition of a group of assets. ASU 2010-02 was effective for us on December 15, 2009 and requires retrospective restatement of our consolidated financial statements for all periods presented in this filing. We have adopted the amended provisions of ASU 2010-12 as of December 15, 2009 and there was no impact on our consolidated results of operations, cash flows and financial position.

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

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

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

F-15

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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

ASU 2009-06 “Income Taxes (Topic 740) Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Nonpublic Entities,” or ASU 2009-06—In September 2009, the FASB issued ASU 2009-06 which provides implementation guidance on accounting for uncertainty in income taxes and disclosure amendments for nonpublic entities, and amended the ASC Topic 740 “Income Taxes.” We have assessed the impact of ASU 2009-06 on our disclosures, and there is no material impact on our consolidated results of operations, cash flows or financial position.

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

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

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

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

F-16

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

In December 2007, the FASB amended guidance relating to business combinations, which requires the acquiring entity in a business combination subsequent to January 1, 2009 to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. We adopted these amended provisions effective January 1, 2009, and have accounted for all transactions with closing dates subsequent to adoption in accordance with the revised provisions of this standard.

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

ASC 815 “Derivatives and Hedging,” or ASC 815—In March 2008, the FASB amended guidance relating to derivatives and hedging to require disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted these amended provisions effective January 1, 2009, and have included all required disclosures in these financial statements. The amended provisions impact only disclosures, so there was no effect on our consolidated results of operations, cash flows or financial position as a result of adoption.

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

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

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

F-17

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

ASC 855 “Subsequent Events,” or ASC 855—In May 2009, the FASB amended guidance relating to subsequent events, which sets forth the recognition and disclosure requirements for events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted these amended provisions effective June 30, 2009, and there was no effect on our consolidated results of operations, cash flows or financial position as a result of adoption. All appropriate disclosure of subsequent events is made within the footnotes.

2. Acquisitions and Contributions to DCP Partners

Acquisitions

Acquisition of Various Gathering, Pipeline and Compression Assets—In November 2009, DCP Partners acquired certain companies that held natural gas gathering and treating assets for $45 million from MichCon Pipeline Company, or MichCon, a subsidiary of DTE Energy. The results of these assets operations have been included in the consolidated financial statements since the date of the acquisition. The assets are located in northern Michigan, adjacent to DCP Partners’ existing Michigan assets. These assets provide essential services for gas produced from the Antrim Shale formation. The purchase price allocation is as follows:


	(millions)
Property, plant and equipment	$	28
Intangible assets		16
Goodwill		3
Other liabilities		(2	)

Total purchase price allocation	$	45

Contributions to DCP Partners

DCP East Texas Holdings, LLC—On April 1, 2009, we contributed an additional 25.1% membership interest in East Texas to DCP Partners in exchange for 3,500,000 DCP Partners Class D units. The Class D units converted into DCP Partners’ common units on a one-for-one basis on August 17, 2009, and the holders of the Class D units received the DCP Partners’ second quarter distribution on August 14, 2009, including the payment of DCP Partners’ second quarter distribution. We also provided a fixed price NGL derivative by NGL component for the period of April 2009 to March 2010. We will continue to be responsible for 75% of certain East Texas operating and capital expenditures from April 1, 2009 through completion of the capital projects, for a period not to exceed three years. We will continue to include East Texas and Discovery in our financial statements, through the consolidation of DCP Partners.

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

3. Agreements and Transactions with Affiliates

The following table summarizes our transactions with affiliates:


	Year Ended December 31,
	2009		2008		2007
	(millions)
ConocoPhillips (a):
Sales of natural gas and petroleum products to affiliates	$	2,097	$	3,413	$	2,787
Transportation, storage and processing	$	24	$	17	$	17
Purchases of natural gas and petroleum products from affiliates	$	356	$	689	$	489
Operating and general and administrative expenses	$	5	$	2	$	1
Spectra Energy:
Sales of natural gas and petroleum products to affiliates	$	—	$	—	$	2
Transportation, storage and processing	$	1	$	—	$	4
Purchases of natural gas and petroleum products from affiliates	$	182	$	172	$	123
Operating and general and administrative expenses	$	—	$	7	$	13
Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	43	$	94	$	95
Transportation, storage and processing	$	14	$	26	$	23
Purchases of natural gas and petroleum products from affiliates	$	112	$	184	$	169

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

We had accounts receivable and accounts payable with affiliates as follows:


	December 31,
	2009			2008
	(millions)
ConocoPhillips:
Accounts receivable	$	237		$	191
Accounts payable	$	(41	)	$	(26	)
Spectra Energy:
Accounts receivable	$	2		$	16
Accounts payable	$	(27	)	$	(16	)
Unconsolidated affiliates:
Accounts receivable	$	16		$	14
Accounts payable	$	(22	)	$	(6	)

ConocoPhillips

Long-term NGL Purchases Contract and Transactions—We sell a portion of our residue gas and NGLs to ConocoPhillips and its subsidiaries, including CP Chem. In addition, we purchase natural gas from ConocoPhillips. Under 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

F-19

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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.

Spectra Energy

Commodity Transactions—We sell a portion of our residue gas and NGLs to, purchase natural gas and other petroleum products from, and provide gathering, transportation and other services to Spectra Energy and its 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 accounts receivable—affiliates as of December 31, 2009 and 2008 are insurance recovery receivables of $2 million and $13 million, respectively. During the year ended December 31, 2007, we recorded hurricane related business interruption insurance recoveries of $4 million, included in the consolidated statements of operations as transportation, storage and processing. For the years ended December 31, 2009 and 2008, no business interruptions were recorded.

DCP Partners entered into a propane supply agreement with Spectra Energy, effective May 1, 2008 and terminating April 30, 2014, which provides DCP Partners propane supply at its marine terminal for up to approximately 120 million gallons of propane annually.

Transactions with other unconsolidated affiliates

We sell a portion of our residue gas and NGLs to, purchase 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.

4. Inventories

Inventories were as follows:


	December 31,
	2009		2008
	(millions)
Natural gas held for resale	$	19	$	7
NGLs		64		36

Total inventories	$	83	$	43

F-20

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

5. Property, Plant and Equipment

Property, plant and equipment by classification was as follows:


	Depreciable Life	December 31,
	Depreciable Life	2009			2008
		(millions)
Gathering	15 - 30 years	$	3,764		$	3,633
Processing	25 - 30 years		2,383			2,134
Transportation	25 - 30 years		1,558			1,329
Underground storage	20 - 50 years		134			141
General plant	3 - 5 years		235			219
Construction work in progress			218			367

			8,292			7,823
Accumulated depreciation			(3,370	)		(2,987	)

Property, plant and equipment, net		$	4,922		$	4,836

Depreciation expense for the years ended December 31, 2009, 2008 and 2007 was $384 million, $344 million and $304 million, respectively. Interest capitalized on construction projects in 2009, 2008 and 2007, was $11 million, $10 million and $4 million, respectively. At December 31, 2009, we had non-cancelable purchase obligations of $47 million for capital projects anticipated to be completed in 2010.

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 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,
	2009			2008
	(millions)
Balance, beginning of period	$	68		$	59
Accretion expense		5			5
Liabilities incurred		1			5
Liabilities settled		(1	)		(1	)

Balance, end of period	$	73		$	68

F-21

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

6. Goodwill and Intangible Assets

The changes in carrying amount of goodwill are as follows:


	December 31,
	2009		2008
	(millions)
Goodwill, beginning of period	$	658	$	649	*
Acquisitions		4		9

Goodwill, end of period	$	662	$	658

Goodwill increased during 2009 by $3 million as a result of the amount that we recognized in connection with our acquisition of certain companies that held natural gas gathering and treating assets from MichCon, and by $1 million for the amount we recognized for the final purchase price allocation of the Michigan Pipeline & Processing, LLC, or MPP, acquisition. Goodwill increased during 2008 by $6 million as a result of the amount that we recognized in connection with our acquisition of MPP, and by $3 million for the final purchase price allocation for the Momentum Energy Group Inc., or MEG, acquisition.

* During 2009, we identified other purchase price adjustments to properly account for deferred taxes that should have been established as a result of 2007 MEG business combination. As a result of this adjustment, goodwill and net deferred tax liabilities were increased by $93 million, which has been reflected in the beginning of period goodwill balance, but previously was not.

We perform an annual goodwill assessment and when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of the reporting unit. We used 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 and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment test indicated that our reporting units’ fair value exceeded the carrying or book value; therefore, we have not recorded any impairment charges during the years ended December 31, 2009, 2008 and 2007.

If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Intangible assets consist primarily of customer contracts and related relationships, including commodity purchase, transportation and processing contracts. The gross carrying amount and accumulated amortization for intangible assets are included in the consolidated balance sheets as intangible assets, net, and are as follows:


	December 31,
	2009			2008
	(millions)
Gross carrying amount	$	426		$	426
Accumulated amortization		(113	)		(107	)

Intangible assets, net	$	313		$	319

F-22

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Intangible assets increased in 2009 by $16 million as a result of our acquisition of certain companies that held natural gas gathering and treating assets from MichCon. Intangible assets increased in 2008 by $20 million as a result of the MPP acquisition.

Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

For the years ended December 31, 2009, 2008 and 2007 we recorded amortization expense of $21 million, $21 million and $12 million, respectively. The remaining amortization periods range from one year to 25 years, with a weighted average remaining period of approximately 21 years.

Estimated amortization for these contracts for the next five years and thereafter is as follows as of December 31, 2009:


Estimated Amortization
(millions)
2010	$	21
2011		21
2012		21
2013		21
2014		15
Thereafter		214

Total	$	313

7. Investments in Unconsolidated Affiliates

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


	2009 and 2008 Ownership		December 31,
	2009 and 2008 Ownership		2009		2008
			(millions)
Discovery Producer Services LLC	40.00	%	$	107	$	105
Main Pass Oil Gathering Company	66.67	%		37		43
Mont Belvieu I	20.00	%		13		11
Sycamore Gas System General Partnership	48.45	%		9		10
Other unconsolidated affiliates	Various			9		10

Total investments in unconsolidated affiliates			$	175	$	179

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, a natural gas pipeline from offshore deep water in the Gulf of Mexico that transports gas to its processing plant in Larose, Louisiana with a design capacity of 600 MMcf/d and approximately 300 miles of pipe, and laterals in the Gulf of Mexico. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $38 million and $40 million at December 31, 2009 and 2008, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

F-23

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Main Pass Oil Gathering Company—We own 66.67% of 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, with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we 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 $10 million and $11 million at December 31, 2009 and 2008, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.

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 $8 million and $9 million at December 31, 2009 and 2008, 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 $5 million and $6 million at December 31, 2009 and 2008, respectively, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Equity in earnings of unconsolidated affiliates amounted to the following:


	Year Ended December 31,
	2009			2008			2007
	(millions)
Discovery Producer Services LLC	$	16		$	17		$	24
Main Pass Oil Gathering Company		5			2			1
Mont Belvieu I		2			(1	)		1
Sycamore Gas System General Partnership		(1	)		—			(1	)
Other unconsolidated affiliates		2			2			4

Total equity in earnings of unconsolidated affiliates		24			20			29
Distributions from unconsolidated affiliates		(35	)		(44	)		(32	)

Equity in earnings of unconsolidated affiliates, net of distributions	$	(11	)	$	(24	)	$	(3	)

The following summarizes combined financial information of unconsolidated affiliates:


	Year Ended December 31,
	2009		2008		2007
	(millions)
Income Statement:
Operating revenues	$	247	$	336	$	354
Operating expenses	$	186	$	307	$	297
Net income	$	59	$	34	$	61

F-24

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007


	December 31,
	2009			2008
	(millions)
Balance sheet:
Current assets	$	80		$	86
Long-term assets		537			542
Current liabilities		(29	)		(60	)
Long-term liabilities		(43	)		(26	)

Net assets	$	545		$	542

8. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities, as well as short-term and restricted investments, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a market participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

•

Level 1—inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

•

Level 2—inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•

Level 3—inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil, or natural gas futures) or over–the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed on the NYMEX exchange with a highly rated broker dealer serving as the clearinghouse for individual transactions.

Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk, and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate based upon observable data. In instances where we utilize an interpolated value, and it is considered significant to the

F-26

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

valuation of the contract as a whole, we would classify the instrument within Level 2. In certain limited instances, we may extrapolate based upon the last readily observable data, developing our own expectation of fair value. To the extent that we have utilized extrapolated data, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

We also engage in the business of trading energy related products and services, which expose us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which may not be as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

We use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our floating rate debt for fixed rate debt or our fixed rate debt for floating rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar characteristics, adjusted by the credit spread between our company and the LIBOR instrument. Given that a significant portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified as Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Short-Term and Restricted Investments

We are required to post collateral to secure the term loan portion of DCP Partners’ credit facility, and may elect to invest a portion of our available cash balances in various financial instruments such as commercial paper and money market instruments. The money market instruments are generally priced at acquisition cost, plus accreted interest at the stated rate, which approximates fair value, without any additional adjustments. However, given that there is no observable exchange traded market for identical money market securities, we have classified these instruments within Level 2. Investments in commercial paper are priced using a yield curve for similarly rated instruments, and are classified within Level 2. As of December 31, 2009 nearly all of our short-term and restricted investments were held in the form of money market securities.

F-27

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

The following table presents the financial instruments carried at fair value as of December 31, 2009 and 2008, by consolidated balance sheet caption and by valuation hierarchy, as described above:


	December 31, 2009												December 31, 2008
	Level 1			Level 2			Level 3			Total Carrying Value			Level 1			Level 2			Level 3			Total Carrying Value
	(millions)
Current assets:
Commodity derivatives (a)	$	72		$	111		$	73		$	256		$	34		$	175		$	210		$	419
Interest rate derivatives (a)	$	—		$	3		$	—		$	3		$	—		$	—		$	—		$	—
Available-for-sale securities (b)	$	—		$	—		$	—		$	—		$	—		$	15		$	—		$	15
Long-term assets:
Commodity derivatives (c)	$	9		$	14		$	18		$	41		$	61		$	36		$	22		$	119
Restricted investments	$	—		$	10		$	—		$	10		$	—		$	60		$	—		$	60
Current liabilities (d):
Commodity derivatives	$	(20	)	$	(101	)	$	(88	)	$	(209	)	$	(79	)	$	(145	)	$	(155	)	$	(379	)
Interest rate derivatives	$	—		$	(20	)	$	—		$	(20	)	$	—		$	(19	)	$	—		$	(19	)
Long-term liabilities (e):
Commodity derivatives	$	(3	)	$	(57	)	$	(6	)	$	(66	)	$	(8	)	$	(6	)	$	(44	)	$	(58	)
Interest rate derivatives	$	—		$	(12	)	$	—		$	(12	)	$	—		$	(23	)	$	—		$	(23	)

(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.

(b)	Included in cash and cash equivalents in our consolidated balance sheets.

(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.

(d)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.

(e)	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable

F-28

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers In/Out of Level 3” caption.

We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.


	Beginning Balance			Net Realized and Unrealized Gains (Losses) Included in Earnings			Transfers In/Out of Level 3 (a)			Purchases, Issuances and Settlements, Net			Ending Balance			Net Unrealized Gains (Losses) Still Held Included in Earnings (b)
	(millions)
Year ended December 31, 2009:
Commodity derivative instruments:
Current assets	$	210		$	33		$	—		$	(170	)	$	73		$	73
Long-term assets	$	22		$	(4	)	$	—		$	—		$	18		$	(1	)
Current liabilities	$	(155	)	$	(30	)	$	3		$	94		$	(88	)	$	(88	)
Long-term liabilities	$	(44	)	$	38		$	—		$	—		$	(6	)	$	38

Year ended December 31, 2008:
Commodity derivative instruments:
Current assets	$	125		$	143		$	—		$	(58	)	$	210		$	210
Long-term assets	$	21		$	2		$	(1	)	$	—		$	22		$	1
Current liabilities	$	(112	)	$	(101	)	$	—		$	58		$	(155	)	$	(155	)
Long-term liabilities	$	(11	)	$	(33	)	$	—		$	—		$	(44	)	$	(33	)

(a)	Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

(b)	Represents the amount of total gains or losses for the period, included in trading and marketing gains or losses, attributable to the change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held at December 31, 2009 and 2008.

Estimated Fair Value of Financial Instruments

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

The fair value of restricted investments, accounts receivable, accounts payable and short-term borrowings 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 derivative instruments are carried at fair value. As of December 31, 2009, the carrying and fair value of our long-term debt, including current maturities of long-term debt, was $3,641 million and $3,830 million, respectively. As of December 31, 2008, the carrying and fair value of our long-term debt, including current maturities of long-term debt, was

F-29

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

$3,286 and $3,030, respectively. We determine the fair value of our variable rate debt based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace.

9. Financing

Long-term debt was as follows:


	December 31,
	2009			2008
	(millions)
Debt securities:
Issued August 2000, interest at 7.875% payable semiannually, due August 2010 (a)	$	800		$	800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011 (b)		250			250
Issued November 2008, interest at 9.700% payable semiannually, due December 2013		250			250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015		200			200
Issued February 2009, interest at 9.750% payable semiannually, due March 2019		450			—
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (c)		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			450
DCP Midstream’s $450 million credit facility revolver, weighted-average interest rate of 2.69% as of December 31, 2008 , due April 2012		—			360
DCP Partners’ credit facility revolver, weighted-average variable interest rate of 0.69% and 2.08%, respectively, due June 2012 (d)		603			596
DCP Partners’ credit facility term loan, variable interest rate of 0.34% and 1.54%, respectively, due June 2012 (e)		10			60
Fair value adjustments related to interest rate swap fair value hedges (a) (b) (c)		40			43
Unamortized discount		(12	)		(7	)
Current maturities of long-term debt		(800	)		—

Long-term debt	$	2,841		$	3,602

(a)	In July 2009, $500 million of debt was swapped to a floating interest rate obligation.

(b)	In July 2009, $200 million of debt was swapped to a floating interest rate obligation.

(c)	In December 2008, the swaps associated with this debt were terminated. The remaining fair value of approximately $40 million related to the swaps is being amortized as a reduction to interest expense through the maturity date of the debt.

(d)

$575 million of interest rate exposure has been swapped to a fixed interest rate obligation with effective fixed interest rates ranging from 2.26% to 5.19%, for a net effective interest rate of 4.41% on the $603 million of outstanding debt under the DCP Partners revolving credit facility as of December 31, 2009.

(e)	The term loan facility is fully secured by restricted investments.

F-30

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2009:


Debt Maturities
(millions)
2010	$	800
2011		250
2012		613
2013		250
2014		—
Thereafter		1,700

		3,613
Fair value adjustments related to interest rate swap fair value hedges		40
Unamortized discount		(12	)
Current maturities of long-term debt		(800	)

Long-term debt	$	2,841

Debt Securities—In February 2009, we issued $450 million principal amount of 9.75% Senior Notes due 2019, or the 9.75% Notes, for proceeds of $441 million, net of unamortized discounts and related offering costs. The 9.75% Notes mature and become due and payable on March 15, 2019. We will pay interest semiannually on March 15 and September 15 of each year, our first payment was on September 15, 2009. The net proceeds from this offering were used for general corporate purposes, which included repayment of outstanding borrowings.

In November 2008, we issued $250 million principal amount of 9.70% Senior Notes due 2013, or the 9.70% Notes, for proceeds of $248 million, net of unamortized discounts and related offering costs. The 9.70% Notes mature and become due and payable on December 1, 2013. We will pay interest semiannually on June 1 and December 1 of each year, beginning June 1, 2009. We used $200 million of the proceeds of this offering to pay down our 364-day agreement that we entered into in April 2008 and the remainder was used for general corporate purposes.

In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or the 6.75% Notes, for proceeds of $444 million, net of unamortized discounts and related offering costs. The 6.75% Notes mature and become due and payable on September 15, 2037. We pay interest semiannually on March 15 and September 15 of each year.

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

DCP Midstream’s Credit Facilities with Financial Institutions—We have a $450 million revolving credit facility, or the $450 Million Facility, which matures in April 2012 and is used to support our commercial paper program, and for working capital and other general corporate purposes. The $450 Million Facility may also be used for letters of credit. Any outstanding borrowings under the $450 Million Facility at maturity may, at our option, be converted into an unsecured one-year term loan. As of December 31, 2009, the available capacity under the $450 Million Facility was $445 million and there were no outstanding borrowings. As of December 31, 2008, there were outstanding borrowings of $360 million. As of December 31, 2009 and 2008, there were $5 million and $8 million in letters of credit outstanding, respectively. We had no commercial paper outstanding as of December 31, 2009 and 2008.

F-31

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Indebtedness under the $450 Million Facility bears interest at a rate equal to, at our option and based on our current debt rating, either: (1) London Interbank Offered Rate, or 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 $450 Million Facility incurs an annual facility fee of 0.07% based on our credit rating on the drawn and undrawn portions.

The $450 Million Facility requires us to maintain a consolidated leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, in each case as is defined by the $450 Million Facility) of (a) not more than 5.0 to 1.0, and (b) on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated), following the consummation of qualifying asset acquisitions as defined by the $450 Million Facility, in the midstream energy business of not more than 5.5 to 1.0.

In June 2009, we terminated our $350 million 364-day revolving credit facility agreement, and expensed $3 million of deferred financing costs relating to the early termination of this facility, which would have been amortized through the maturity date of November 2009. This facility was used to support our commercial paper program, for working capital requirements and for other general corporate purposes. There were no borrowings outstanding under this facility as of December 31, 2008.

In April 2008, we entered into a $300 million 364-day credit agreement, which was fully funded in April 2008, and matured in April 2009. The proceeds were used to partially fund the April 2008 dividend to our parents. We repaid the remaining balance of the credit agreement in February 2009 with proceeds from the issuance of the 9.75% Notes discussed above.

DCP Midstream Partners’ Credit Facilities with Financial Institutions—DCP Partners has a 5-year credit agreement, or the DCP Partners’ Credit Agreement, which matures on June 21, 2012 and consists of an $815 million revolving credit facility and a $10 million term loan facility at December 31, 2009. These amounts are net of $25 million non-participation by Lehman Brothers Commercial Bank, a lender under DCP Partners’ Credit Agreement. At both December 31, 2009 and 2008, DCP Partners had less than $1 million of letters of credit outstanding under the DCP Partners’ Credit Agreement. As of December 31, 2009, the available capacity under the revolving credit facility was $212 million. As of December 31, 2009 and 2008 there were outstanding borrowings of $603 million and $596 million, respectively. 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 sheets as of December 31, 2009 and 2008.

Under the DCP Partners’ 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 DCP Partners’ credit rating. The revolving credit facility incurs an annual facility fee of 0.07% to 0.125% depending on DCP Partners’ credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to; (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Bank’s prime rate or the Federal Funds rate plus 0.50%.

The DCP Partners’ Credit Agreement requires DCP Partners to maintain a consolidated leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of (a) not more than 5.0 to 1.0, and (b) on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated), following the consummation of qualifying asset acquisitions as defined by the DCP Partners’ Credit Agreement, in the midstream energy business of not more than 5.5 to 1.0. Prior to DCP Partners’ receiving an investment grade

F-32

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

credit rating from Standard & Poor’s Ratings Group in December 2009, the DCP Partners’ Credit Agreement also required DCP Partners to maintain an interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense, in each case as is defined by the DCP Partners’ Credit Agreement) of greater than or equal to 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. As a result of its investment grade credit rating, DCP Partners is no longer required to maintain this interest coverage ratio.

Other Agreements—As of December 31, 2009, DCP Partners had an outstanding letter of credit with a counterparty to its commodity derivative instruments of $10 million, which reduces the amount of cash DCP Partners may be required to post as collateral. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under the DCP Partners’ Credit Agreement.

Other Financing—In November 2009, DCP Partners issued 2,500,000 common limited partner units at $25.40 per unit, and in December 2009, DCP Partners issued an additional 375,000 common limited partner units to the underwriters who exercised their overallotment option. DCP Partners received proceeds of approximately $70 million, net of offering costs.

In April 2009, we contributed an additional 25.1% membership interest in East Texas to DCP Partners in exchange for 3,500,000 DCP Partners Class D units. The Class D units converted into DCP Partners’ common units on a one-for-one basis on August 17, 2009, and the holders of the Class D units received the DCP Partners’ second quarter distribution on August 14, 2009.

In March 2008, DCP Partners issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132 million, net of offering costs.

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

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures by using physical and financial derivative instruments. All of our derivative activities are conducted under the governance of an internal Risk Management Committee that establishes policies, limiting exposure to market risk and requiring 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. The following briefly describes each of the risks that we manage.

Commodity Price Risk

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized in the tables below.

Natural Gas Asset Based Trading and Marketing

Our natural gas asset based trading and marketing activities engage 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

F-33

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage commodity price risk related to owned and leased natural gas storage and pipeline assets by engaging in natural gas asset based trading and marketing. The commercial activities related to our natural gas asset based trading and marketing primarily consist of time spreads and basis spreads.

We may execute a time spread transaction when the difference between the current price of natural gas (cash or futures) and the futures market price for natural gas exceeds our cost of storing physical gas in our owned and/or leased storage facilities. The time spread transaction allows us to lock in a margin when this market condition exists. A time spread transaction is executed by establishing a long gas position at one point in time and establishing a corresponding short gas position at a future point in time. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statement of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

We may execute basis spread transactions when the market price differential between locations on a pipeline asset exceeds our cost of transporting physical gas through our owned and/or leased pipeline asset. When this market condition exists, we may execute derivative instruments around this differential at the market price. This basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. As discussed above, the accounting for physical gas purchases and sales and the accounting for the derivative instruments used to manage such purchases and sales differ, and may subject our earnings to market volatility, even though the transaction represents an economic hedge in which we have locked in a future margin.

Additionally, in order for our storage facilities to remain operational, we maintain a minimum level of base gas in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. In the fourth quarter of 2008 we commenced a capacity expansion project for one of our storage caverns, which required us to sell all of the base gas within the cavern. During 2009, the expansion project was completed and base gas was repurchased to restore our storage cavern to operation. To mitigate the risk associated with the forecasted re-purchase of base gas, we executed a series of derivative financial instruments, which have been designated as cash flow hedges. The cash paid upon settlement of these hedges economically offsets the cash paid to purchase the base gas. A deferred loss of $3 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

NGL Proprietary Trading

Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations 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. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations.

F-34

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Commodity Cash Flow Protection Activities at DCP Partners

As a result of DCP Partner’s operations of gathering, processing and transporting natural gas, DCP Partners takes title to a portion of residue gas, NGLs and condensate, which are considered to be Partners’ equity volumes. The possession of and the related operations of transporting and marketing of NGLs, creates commodity price risk due to market changes in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. DCP Partners has mitigated a portion of its expected natural gas, NGL and condensate commodity price risk associated with these equity volumes through 2014 with natural gas, crude oil and NGL derivatives. These transactions are primarily accomplished through the use of swaps that exchange DCP Partners floating rate price risk for a fixed rate, but the type of instrument that is used to mitigate risk may vary depending upon DCP Partners’ risk objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations.

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.

Interest Rate Fair Value Hedges

In July 2009, we entered into interest rate swaps to convert the fixed interest rate on $500 million of debt securities under our 7.875% Notes due August 2010 and $200 million of debt securities under our 6.875% Notes due February 2011 to a floating rate to optimize our debt portfolio. These interest rate fair value hedges are at a floating rate based on one month LIBOR, which resets monthly and is paid semi-annually through their expiration in August 2010 and February 2011, respectively. The swaps meet conditions that permit the assumption of no ineffectiveness. As such, for the life of the swaps, no ineffectiveness will be recognized.

Additionally, we previously had fair value interest rate hedges that were terminated in December 2008. As a result of this termination, the fair value of the underlying debt being hedged has been adjusted and will be amortized as a reduction to our interest expense over the remaining term of the debt through 2030.

Interest Rate Cash Flow Hedges

DCP Partners mitigates a portion of its interest rate risk with interest rate swaps, which reduces its exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swap agreements convert the interest rate associated with an aggregate of $575 million of the indebtedness outstanding under Partner’s revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All of Partner’s 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 effect that these swaps have on our consolidated financial statements, as well as the effect that is expected over the upcoming 12 months is summarized in the charts below. 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. $425 million of the agreements reprice prospectively approximately every 90 days and the remaining $150 million of the agreements reprice prospectively approximately every 30 days. Under the terms of the interest rate swap

F-35

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

agreements, DCP Partners pays fixed rates ranging from 2.26% to 5.19%, and receives interest payments based on the three-month and one-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense.

We previously had interest rate cash flow hedges in place that were terminated in 2000. As a result, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense through the remaining term of the debt through 2030, as the underlying transactions impact earnings.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.

•

In the event that we were to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties may have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

•

In some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. For example, if we were to fail to make a required interest or principal payment on a debt instrument, above a predefined threshold level, and after giving effect to any applicable notice or grace period as defined in the ISDA contracts, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative positions.

•

Additionally, if DCP Partners, our consolidated subsidiary, were to have an effective event of default under its credit agreement that occurs and is continuing, DCP Partners’ ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or interest rate swap instruments are in either a net asset or net liability position.

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. As of December 31, 2009, we had $107 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. If a credit-risk related event were to occur, we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2009, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $41 million.

F-36

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

As of December 31, 2009, DCP Partner’s interest rate swaps were in a net liability position of $32 million, of which, the entire amount is subject to credit-risk related contingent features. If DCP Partners were to have an event of default relative to any covenants of its credit agreement, that occurs and is continuing, the counterparties to DCP Partners’ swap instruments may have the right to request early termination and settlement of the outstanding derivative position.

Summarized Derivative Information

The following summarizes the balance within AOCI, net of noncontrolling interest, relative to our commodity and interest rate cash flow hedges:


	December 31,
	2009			2008
	(millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(3	)	$	(1	)
Interest rate cash flow hedges:
Net deferred losses in AOCI		(14	)		(16	)

Total AOCI	$	(17	)	$	(17	)

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked to market each period, and the location of each within our consolidated balance sheets, by major category, is summarized as follows:


	December 31,
Balance Sheet Line Item	2009		2008
	(millions)
Derivative Assets Designated as Hedging Instruments:

Interest rate derivatives:
Unrealized gains on derivative instruments—current	$	3	$	—
Unrealized gains on derivative instruments—long-term		—		—

	$	3	$	—

Commodity derivatives:
Unrealized gains on derivative instruments—current	$	1	$	—
Unrealized gains on derivative instruments—long-term		—		—

	$	1	$	—

Derivative Assets Not Designated as Hedging Instruments:

Commodity derivatives:
Unrealized gains on derivative instruments—current	$	255	$	419
Unrealized gains on derivative instruments—long-term		41		119

	$	296	$	538

F-37

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007


	December 31,
Balance Sheet Line Item	2009			2008
	(millions)
Derivative Liabilities Designated as Hedging Instruments:

Interest rate derivatives:
Unrealized losses on derivative instruments—current	$	(20	)	$	(19	)
Unrealized losses on derivative instruments—long-term		(12	)		(23	)

	$	(32	)	$	(42	)

Commodity derivatives:
Unrealized losses on derivative instruments—current	$	(3	)	$	—
Unrealized losses on derivative instruments—long-term		—			—

	$	(3	)	$	—

Derivative Liabilities Not Designated as Hedging Instruments:

Commodity derivatives:
Unrealized losses on derivative instruments—current	$	(206	)	$	(379	)
Unrealized losses on derivative instruments—long-term		(66	)		(58	)

	$	(272	)	$	(437	)

The following table summarizes the impact on our consolidated statement of operations of our derivative instruments that are accounted for using the fair value hedge method of accounting.


Derivatives and Hedged Items in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Earnings	Amount of Gain (Loss) Recognized in Earnings
	Location of Gain (Loss) Recognized in Earnings	Year Ended December 31,
		2009			2008
		(millions)
Interest rate derivatives	Interest expense	$	3		$	29
Long-term debt hedged items	Interest expense		(2	)		(35	)

Total		$	1		$	(6	)

The following table summarizes the impact on our consolidated balance sheet and consolidated statement of operations of our derivative instruments, net of noncontrolling interest, that are accounted for using the cash flow hedge method of accounting.


	Gain (Loss) Recognized in AOCI on Derivatives— Effective Portion						Gain (Loss) Reclassified from AOCI to Earnings— Effective Portion						Gain (Loss) Recognized in Income on Derivatives— Ineffective Portion and Amount Excluded from Effectiveness Testing					Deferred Gains (Losses) in AOCI Expected to be Reclassified into Earnings Over the Next 12 Months
	Year Ended December 31,
	2009			2008			2009			2008			2009		2008
	(millions)																	(millions)
Commodity derivatives	$	(2	)	$	(1	)	$	—		$	(1	)(a)	$	—	$	—	(a)(c)	$	—
Interest rate derivatives	$	(4	)	$	(10	)	$	(6	)	$	(4	)(b)	$	—	$	—	(b)(c)	$	(8	)

(a)	Included in sales of natural gas and petroleum products in our consolidated statements of operations.

F-38

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

(b)	Included in interest expense in our consolidated statements of operations.

(c)	For the years ended December 31, 2009 and 2008, 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.

Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:


	Year Ended December 31,
Commodity Derivatives: Statement of Operations Line Item	2009			2008			2007
	(millions)
Realized gains (losses)	$	127		$	(93	)	$	59
Unrealized (losses) gains		(77	)		194			(102	)

Trading and marketing gains, net	$	50		$	101		$	(43	)

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

The following table represents, by commodity type, our net long or short positions, as well as the number of outstanding contracts that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below. Additionally, relative to the hedging of certain of our storage and/or transportation assets, we may execute basis transactions for natural gas, which may result in a net long/short position of zero.


	December 31, 2009
	Crude Oil			Natural Gas			Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Long (Short) Positions (Bbls)		Number of Contracts	Net Long (Short) Position (MMBtu)		Number of Contracts	Net Long (Short) Position (Bbls)	Number of Contracts	Net Long (Short) Position (MMBtu)		Number of Contracts
2010	(1,479,972	)	525	(9,478,500	)	240	1,021,295	580	(30,160,000	)	261
2011	(749,000	)	80	(2,084,000	)	73	1,857,000	32	(5,315,000	)	65
2012	(388,750	)	33	(734,600	)	43	—	—	(366,000	)	1
2013	(748,250	)	4	(365,000	)	1	—	—	(365,000	)	1
2014	(365,000	)	3	—		—	—	—	—		—

Depending upon our view of the interest rate market, we or DCP Partners may periodically enter into interest rate swap agreements. As of December 31, 2009, we had interest rate swap instruments outstanding, which in the aggregate, exchanged $700 million of our fixed rate obligation for a floating rate obligation. $500 million of these swaps expire in August 2010 and the remaining $200 million expire in February 2011. As of December 31, 2009, DCP Partners had swaps outstanding with a notional value between $25 million and $150 million, which, in aggregate, exchanged $575 million of DCP Partners’ floating rate obligation for a fixed rate obligation through June 2012.

F-39

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Other Risks

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 commodities in future periods, as well as select operating expense contracts. These transactions will impact earnings in the same manner as any other purchase and sale that is accounted for under the accrual basis of accounting.

Credit Risk and Collateral

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 various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides 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 language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and 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, 2009, we held cash deposits of $49 million included in other current liabilities and letters of credit of $74 million from counterparties to secure their future performance under financial or physical contracts. We had cash deposits with counterparties of less than $1 million, included in other current assets, to secure our obligations to provide future services or to perform under financial contracts. As of December 31, 2009, DCP Partners had an outstanding letter of credit with a counterparty to its commodity derivative instruments of $10 million. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under the DCP Partners’ Credit Agreement. This letter of credit reduces the amount of cash DCP Partners may be required to post as collateral. As of December 31, 2009, DCP Partners had no other cash collateral posted with counterparties to our commodity derivative instruments. 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.

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.

F-40

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

11. Noncontrolling Interest

Noncontrolling interest represents the ownership interests of third-party entities in the net assets of consolidated affiliates, including ownership interest of DCP Partners’ public unitholders, through DCP Partners’ publicly traded common units, in net assets of DCP Partners and the noncontrolling interest which is recorded in DCP Partners’ consolidated balance sheets. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party investors’ interest in our consolidated balance sheet amounts shown as noncontrolling interest. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third-party investors.

12. Equity-Based Compensation

We recorded equity-based compensation (benefit) expense as follows, the components of which are further described below:


	Year Ended December 31,
	2009		2008			2007
	(millions)
DCP Midstream, LLC Long-Term Incentive Plan (2006 Plan)	$	8	$	—		$	4
DCP Partners’ Long-Term Incentive Plan (DCP Partners’ Plan)		2		(1	)		2
Duke Energy 1998 Plan and Spectra Energy Long-Term Incentive Plan		—		(1	)		1

Total	$	10	$	(2	)	$	7


	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2009 (millions)		Estimated Forfeiture Rate		Weighted- Average Remaining Vesting (years)
DCP Midstream’s 2006 Plan:
Relative Performance Units (RPUs)	8	$	1	72%	(a)	5
Strategic Performance Units (SPUs)	3	$	5	22%	(a)	1
Phantom Units	5	$	5	23%	(a)	2
DCP Partners’ Phantom Units	3	$	—	22%	(a)	—
DCP Partners’ Plan:
Performance Units	3	$	1	23%-30%		2
Phantom Units	0.5-3	$	—	0%		—
Restricted Phantom Units	3	$	1	23%-30%		2
Duke Energy’s 1998 Plan and Spectra Energy’s 2007 LTIP Plan:
Stock Options (no activity in 2007, 2008 or 2009)	0-10	$	—	5%		2
Stock Based Performance Awards	3	$	—	—		—
Phantom Awards	1-5	$	—	2%		—

(a)	Weighted-average estimated forfeiture rate

F-41

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan—Under our 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, or DERs. The 2006 Plan is administered by the compensation committee of our board of directors. 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. The final performance payout is determined by the compensation committee of our board of directors. After the performance period the value derived from the RPUs is transferred to our Non-Qualified Deferred Compensation plan, and invested according to the participant’s investment elections. Vesting occurs over five years. The DERs are 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 January 1, 2007	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
Forfeited	(5,850	)	$	43.36
Vested or paid in cash	(3,047	)	$	42.86

Outstanding at December 31, 2008	53,270		$	43.44
Forfeited	(530	)	$	43.91
Transferred to Non-Qualified Executive Deferred Compensation Plan (a)	(27,700	)	$	42.90

Outstanding at December 31, 2009	25,040		$	44.02	$	34.55

Expected to vest	11,855		$	43.98	$	34.55

(a)	After the performance period the value derived from the RPUs is transferred to our Non-Qualified Deferred Compensation plan, and invested according to the participant’s investment elections. The Compensation Committee has certified these grants will vest at 170%.

F-42

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Strategic Performance Units—The number of SPUs that will ultimately vest range from 0% to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our board of directors. The DERs are 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 January 1, 2007	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
Granted	112,930		$	35.49
Forfeited	(14,617	)	$	41.86
Vested or paid in cash	(3,047	)	$	42.86

Outstanding at December 31, 2008	235,285		$	39.76
Granted	209,110		$	18.51
Forfeited or cancelled	(7,039	)	$	34.20
Vested or paid in cash (a)	(62,439	)	$	42.94

Outstanding at December 31, 2009	374,917		$	27.48	$	29.26

Expected to vest	297,491		$	28.88	$	29.13

(a)

The 2006 grants vested at 70%.

The estimate of RPUs and SPUs that are expected to vest is based on highly subjective assumptions that could 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.

F-43

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Phantom Units—The DERs 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 January 1, 2007	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
Granted	112,930		$	35.49
Forfeited	(5,270	)	$	39.15

Outstanding at December 31, 2008	141,460		$	37.29
Granted	209,110		$	18.51
Forfeited	(6,040	)	$	32.51
Vested or paid in cash	(680	)	$	43.38

Outstanding at December 31, 2009	343,850		$	25.94	$	28.94

Expected to vest	282,852		$	27.97	$	29.03

DCP Partners’ Phantom Units—The DERs 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 Price Per Unit
Outstanding at January 1, 2007	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
Forfeited	(2,750	)	$	51.10

Outstanding at December 31, 2008	49,000		$	33.39
Vested or paid in cash	(38,250	)	$	28.60

Outstanding at December 31, 2009	10,750		$	50.43	$	29.57

Expected to vest	10,750		$	50.57	$	29.57

DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan—Under 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’

F-44

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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.

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

Performance Units—The number of Performance Units that will ultimately vest range from 0% to 200% 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 are paid in cash at the end of the performance period. The following table presents information related to the Performance Units:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Price Per Unit
Outstanding at January 1, 2007	23,090		$	26.96
Granted	29,610		$	37.29
Forfeited	(5,740	)	$	31.39

Outstanding at December 31, 2007	46,960		$	32.93
Granted	17,085		$	33.85
Forfeited	(12,025	)	$	32.42

Outstanding at December 31, 2008	52,020		$	33.35
Granted	52,450		$	10.05
Vested or paid in cash	(37,330	)	$	34.51

Outstanding at December 31, 2009	67,140		$	14.50	$	29.57

Expected to vest	43,250		$	13.65	$	29.57

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

Phantom Units—In conjunction with its 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. All of these units vested during 2009.

In 2009, DCP Partners granted 16,000 Phantom Units, pursuant to the LTIP, to directors who are not officers or employees of affiliates of DCP Midstream as part of its annual director fees in 2009. All of these units vested during 2009.

In 2008, DCP Partners granted 4,000 Phantom Units, pursuant to the LTIP, to directors who are not officers or employees of affiliates of DCP Midstream as part of its annual director fees in 2008. All of these units vested during 2008.

F-45

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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 its annual director fees for 2007. Of these Phantom Units, 4,000 units vested during 2007 and 500 units vested during 2008.

The DERs are paid quarterly in arrears.

The following table presents information related to the Phantom Units:


	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Price Per Unit
Outstanding at January 1, 2007	24,700		$	24.05
Granted	4,500		$	42.90
Forfeited	(2,333	)	$	24.05
Vested or paid in cash	(6,668	)	$	35.23

Outstanding at December 31, 2007	20,199		$	24.56
Granted	4,000		$	35.88
Forfeited	(4,000	)	$	24.05
Vested or paid in cash	(6,501	)	$	32.91

Outstanding at December 31, 2008	13,698		$	24.05
Granted	16,000		$	10.05
Vested or paid in cash	(29,698	)	$	16.51

Outstanding at December 31, 2009	—		$	—	$	—

Restricted Phantom Units—DCP Midstream Partners’ General Partner’s board of directors awarded restricted phantom LPUs, or RPUs, to key employees under the LTIP. The RPUs are expected to vest over a three year period. The DERs are paid quarterly in arrears. The following table presents information related to the RPUs:


	Units		Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2008	—		$	—
Granted	17,085		$	33.85
Forfeited	(2,395	)	$	35.88

Outstanding at December 31, 2008	14,690		$	33.52
Granted	52,450		$	10.05

Outstanding at December 31, 2009	67,140		$	15.18	$	29.57

Expected to vest	49,785		$	16.30	$	29.57

The estimate of RPUs that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate, which was estimated at 30% for units granted in 2009 and 23% for units granted in 2008.Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statement of operations.

F-46

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash at each reporting period or units 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 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.

F-47

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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 January 1, 2007	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
Exercised	(151,480	)	$	13.45
Forfeited	(106,889	)	$	19.77

Outstanding at December 31, 2008	1,557,587		$	18.19	2.4
Exercised	(166,869	)	$	12.80
Forfeited	(223,926	)	$	16.19

Outstanding at December 31, 2009	1,166,792		$	19.34	2.6	$	2

Exercisable at December 31, 2009	1,166,792		$	19.34	2.6	$	2

The total intrinsic value of options exercised during the years ended December 31, 2009 and 2008, was approximately $1 million at both periods.

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 January 1, 2007	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
Exercised	(68,869	)	$	18.91
Forfeited	(72,400	)	$	28.06

Outstanding at December 31, 2008	795,979		$	27.36	2.4
Exercised	(13,861	)	$	11.93
Forfeited	(183,822	)	$	23.36

Outstanding at December 31, 2009	598,296		$	28.95	1.9	$	1

Exercisable at December 31, 2009	598,296		$	28.95	1.9	$	1

The total intrinsic value of options exercised during the years ended December 31, 2009 and 2008, was less than $1 million and approximately $1 million, respectively.

F-48

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Stock-Based Performance Awards—There were no stock-based performance awards granted during the years ended December 31, 2009 and 2008.

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 January 1, 2007	173,405		$	15.58
Forfeited	(40	)	$	15.38

Outstanding at December 31, 2007	173,365		$	15.58
Vested	(83,762	)	$	15.39
Forfeited	(59,663	)	$	15.39

Outstanding at December 31, 2008	29,940		$	16.50
Vested	(25,329	)	$	16.50
Forfeited	(4,611	)	$	16.50

Outstanding at December 31, 2009	—		$	—	$	—


Spectra Energy 2007 LTIP	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at January 1, 2007	184,083		$	20.93
Vested	(83,309	)	$	18.30
Forfeited	(14,091	)	$	20.42

Outstanding at December 31, 2007	86,683		$	23.54
Vested	(41,884	)	$	23.25
Forfeited	(29,829	)	$	23.25

Outstanding at December 31, 2008	14,970		$	24.94
Vested	(12,665	)	$	24.94
Forfeited	(2,305	)	$	24.94

Outstanding at December 31, 2009	—		$	—	$	—

The total fair value of the performance stock awards that vested during the years ended December 31, 2009 and 2008 was less than $1 million and approximately $2 million, respectively. No awards were granted during the years ended December 31, 2009 and 2008.

Phantom Stock Awards—There were no phantom stock awards granted during the years ended December 31, 2009 and 2008.

F-49

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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 January 1, 2007	112,024		$	15.59
Vested	(29,190	)	$	15.54
Forfeited	(5,624	)	$	15.38

Outstanding at December 31, 2007	77,210		$	15.62
Vested	(24,419	)	$	15.57
Forfeited	(3,287	)	$	15.38

Outstanding at December 31, 2008	49,504		$	15.66
Vested	(22,689	)	$	15.58
Forfeited	(307	)	$	15.38

Outstanding at December 31, 2009	26,508		$	15.72	$	17.21

Expected to vest	25,906		$	15.72	$	17.21


Spectra Energy 2007 LTIP	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at January 1, 2007	104,171		$	21.31
Vested	(59,258	)	$	19.66
Forfeited	(6,308	)	$	22.81

Outstanding at December 31, 2007	38,605		$	23.60
Vested	(12,209	)	$	23.53
Forfeited	(1,644	)	$	23.24

Outstanding at December 31, 2008	24,752		$	23.66
Vested	(11,344	)	$	23.55
Forfeited	(154	)	$	23.24

Outstanding at December 31, 2009	13,254		$	23.76	$	20.51

Expected to vest	12,915		$	23.76	$	20.51

The total fair value of the phantom stock awards that vested during the years ended December 31, 2009 and 2008 was approximately $1 million for both periods. No awards were granted during the years ended December 31, 2009 and 2008.

13. 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 contribute 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 the years ended December 31, 2009, 2008 and 2007 we expensed plan contributions of $22 million, $19 million and $17 million, respectively.

F-50

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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 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.

14. 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) benefit related to this corporation is included in our income tax (expense) benefit, along with state and local taxes of the limited liability company and other subsidiaries.

The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned to Texas. Accordingly, we have recorded current tax expense for the Texas margin tax beginning in 2007. During 2009 and 2008, we acquired properties in Michigan, which imposes a business tax of 0.8% on gross receipts and 4.95% of Michigan taxable income. The sum of gross receipts and income tax is subject to a tax surcharge of 21.99%. Michigan provides tax credits that may reduce our final income tax liability.

Income tax benefit (expense) consists of the following:


	Year Ended December 31,
	2009			2008			2007
	(millions)
Current:
Federal	$	—		$	3		$	(5	)
State		(4	)		(13	)		(11	)
Deferred:
Federal		(14	)		13			4
State		—			—			1

Total income tax (expense) benefit	$	(18	)	$	3		$	(11	)

We had net long-term deferred tax liabilities of $104 million and $90 million * as of December 31, 2009 and 2008, respectively. The net long-term deferred tax liabilities are included in deferred income taxes on the consolidated balance sheets. The deferred tax liabilities of $119 million and $102 million as of December 31, 2009 and 2008, respectively, are primarily associated with depreciation and amortization related to the acquired intangible assets and property, plant and equipment purchased from MEG. Offsetting the deferred tax liabilities are deferred tax assets related to the net operating loss of an affiliate corporation of approximately $15 million and $12 million as of December 31, 2009 and 2008, respectively. The net operating losses begin expiring in 2027. We expect to fully utilize the net operating loss carryovers, and, accordingly we have not provided a valuation allowance for the net deferred tax asset.

* During 2009, the deferred tax liabilities associated with the MEG acquisition were identified and recorded. As a result, goodwill and net deferred tax liabilities were increased by $93 million, which is currently being reflected in the December 31, 2008 net deferred tax liabilities balance, but previously was not.

F-51

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

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. Additionally, some of our subsidiaries are tax paying entities for United States income tax purposes.

15. Commitments and Contingent Liabilities

Litigation—The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. We are currently named as defendants in some of these cases and customers have asserted individual audit claims related to mismeasurement and mispayment. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These claims, 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, including, from time to time, disputes with customers over various measurement and settlement issues.

On February 27, 2009, a jury in the District Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, or El Paso, and against DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP. The lawsuit, filed in December 2006, stemmed from an ongoing commercial dispute involving DCP Partners’ Minden processing plant that dates back to August 2000. During the second quarter of 2009, we filed an appeal in the 14^th Court of Appeals, Texas. El Paso filed an additional lawsuit in the District Court of Webster Parish, Louisiana. The Louisiana court determined in August 2009 that El Paso’s Louisiana claims were barred by the doctrine of res judicata and dismissed the case with prejudice in Louisiana. In January 2010, we and DCP Partners entered into a settlement agreement with El Paso to resolve all claims brought by El Paso pursuant to this matter in Texas and Louisiana. Under the terms of the settlement agreement, we and DCP Partners collectively paid El Paso approximately $4 million. This amount was included in the consolidated balance sheets within other current liabilities as of December 31, 2009. The cases have been dismissed in both Texas and Louisiana.

In March 2008, after receiving regulatory approval, we finalized settlement of a lawsuit alleging migration of acid gas from a storage formation into a third-party producing formation. We obtained the land and 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.

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.

General Insurance—Our insurance coverage is carried with an affiliate of ConocoPhillips and third-party insurers. Our 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 vehicles; (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.

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DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste storage, management, transportation and disposal, and other environmental matters including recently adopted EPA regulations related to reporting of greenhouse gas emissions that become effective in January 1, 2010. 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.

We make expenditures in connection with environmental matters as part of our normal operations. In addition, at December 31, 2009 and 2008, we had liabilities of $16 million and $18 million, respectively, recorded for environmental remediation obligations and $73 million and $68 million, respectively, recorded for asset retirement obligations.

Operating Leases—We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $40 million, $45 million and $41 million in 2009, 2008 and 2007, 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)
2010	$	38
2011		32
2012		27
2013		22
2014		14
Thereafter		13

Total minimum lease payments	$	146

16. Guarantees and Indemnifications

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. We have issued guarantees for certain of our consolidated subsidiaries, however, we are not required to, and have not, recognized such guarantees as a liability in our consolidated financial statements.

F-53

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

17. Supplemental Cash Flow Information


	Year Ended December 31,
	2009		2008		2007
	(millions)
Cash paid for interest:
Cash paid for interest, net of capitalized interest	$	216	$	190	$	159
Cash paid for income taxes, net of income tax refunds	$	10	$	5	$	11

Non-cash investing and financing activities:
Distributions payable to members	$	71	$	—	$	123
Property, plant and equipment acquired with accounts payable	$	24	$	44	$	35
Other non-cash additions of property, plant and equipment	$	10	$	6	$	5

During the years ended December 31, 2009 and 2008, we received distributions from DCP Partners of $37 million and $31 million, respectively, which are eliminated in consolidation.

18. Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2009, 2008 and 2007 are as follows:


	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, 2009
Allowance for doubtful accounts	$	6	$	2	$	—	$	(5	)	$	3
Environmental		18		2		—		(4	)		16
Litigation		4		2		—		—			6
Other (a)		3		—		—		(2	)		1

	$	31	$	6	$	—	$	(11	)	$	26

December 31, 2008
Allowance for doubtful accounts	$	5	$	2	$	—	$	(1	)	$	6
Environmental		12		10		—		(4	)		18
Litigation		15		—		—		(11	)		4
Other (a)		3		—		—		—			3

	$	35	$	12	$	—	$	(16	)	$	31

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

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

(b)	Consists of purchase accounting adjustments for the MEG acquisition in 2007.

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

F-54

DCP MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Years Ended December 31, 2009, 2008 and 2007

19. Subsequent Events

We have evaluated subsequent events occurring through February 26, 2010, the date the consolidated financial statements were issued.

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

In January 2010, we entered into a $350 million revolving credit facility, or the $350 Million Facility, that matures in April 2012. When taken with our existing $450 Million Facility, the $350 Million Facility increases our total revolving credit availability to $800 million. The $350 Million Facility may be used to support our commercial paper program, for working capital requirements and for other general corporate purposes. Indebtedness under the $350 Million Facility bears interest at a rate equal to, at our option and based on our debt rating at December 31, 2009, either: (1) LIBOR plus 2% per year; or (2) the higher of (a) Suntrust’s prime rate per year plus 1.5%, (b) the Federal Funds rate plus 2% per year, or (c) LIBOR plus 2.5% per year. The $350 Million Facility incurs an annual facility fee of 0.5% based on our current debt rating on the drawn and undrawn portions.

In January 2010, our board of directors approved a $79 million dividend that we paid in January 2010.

F-55