Edgar Filing: Duke Energy CORP

Form 10-K/A Amendment No. 1

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

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

For the fiscal year ended December 31, 2006 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 1-32853

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		20-2777218
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

526 South Church Street, Charlotte, North Carolina		28202-1803
(Address of principal executive offices)		(Zip Code)

704-594-6200

(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, without par value		New York Stock Exchange, Inc.

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x



Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2006	$	36,684,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at February 23, 2007		1,257,116,278

PART IV

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K of Duke Energy Corporation (Duke Energy) for the fiscal year ended December 31, 2006 is being filed for the purpose of providing separate audited financial statements of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) in accordance with Rule 3-09 of Regulation S-X. These audited financial statements are included in Item 15, Exhibits and Financial Statement Schedule. Otherwise, this amendment does not update or modify in any way the financial position, results of operations, cash flows or the disclosures in Duke Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, and does not reflect events occurring after the original filing date of March 1, 2007.

Item 15. Exhibits, Financial Statement Schedules.

(a) Financial Statements

The following financial statements and related notes were filed as part of Duke Energy’s Form 10-K filed March 1, 2007:

Duke Energy Corporation:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004

Consolidated Balance Sheets as of December 31, 2006 and 2005

Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004

Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income for the years ended December 31, 2006, 2005 and 2004

Notes to Consolidated Financial Statements

TEPPCO Partners, L.P.:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2005 and 2004

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

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

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

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

Notes to Consolidated Financial Statements

(b) Financial Statement Schedules

(i) The following financial statement schedules were filed as part of Duke Energy’s Form 10-K filed March 1, 2007:

Report of Independent Registered Public Accounting Firm

Schedule II—Valuation and Qualifying Accounts and Reserves

(ii) The following financial statement schedules are included herein this Duke Energy Form 10-K/A pursuant to Rule 3-09 of Regulation S-X:

DCP Midstream, LLC. (formerly Duke Energy Field Services, LLC):

Independent Auditors’ Report

Consolidated Balance Sheets as of December 31, 2006 and 2005

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

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

PART IV

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

Notes to Consolidated Financial Statements

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

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

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

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.

Date: March 21, 2007


DUKE ENERGY CORPORATION (Registrant)

By:		/S/ JAMES E. ROGERS
		James E. Rogers Chairman, President and Chief Executive Officer

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

DCP Midstream, LLC

Denver, Colorado

We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DCP Midstream, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

March 14, 2007

F-1

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

CONSOLIDATED BALANCE SHEETS

As of December 31, 2006 and 2005

(millions)


	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	68		$	59
Short-term investments		437			627
Accounts receivable:
Customers, net of allowance for doubtful accounts of $3 million and $4 million, respectively		933			1,237
Affiliates		283			340
Other		56			59
Inventories		87			110
Unrealized gains on mark-to-market and hedging instruments		242			252
Other		23			22
Total current assets		2,129			2,706
Property, plant and equipment, net		3,869			3,836
Restricted investments		102			364
Investments in unconsolidated affiliates		204			169
Intangible assets:
Commodity sales and purchases contracts, net		58			66
Goodwill		421			421
Total intangible assets		479			487
Unrealized gains on mark-to-market and hedging instruments		29			60
Deferred income taxes		4			3
Other non-current assets		33			86
Other non-current assets—affiliates		47			—
Total assets	$	6,896		$	7,711

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,490		$	2,035
Affiliates		92			42
Other		42			42
Current maturities of long-term debt		—			300
Unrealized losses on mark-to-market and hedging instruments		216			244
Distributions payable to members		127			185
Accrued interest payable		47			45
Accrued taxes		27			46
Other		136			129
Total current liabilities		2,177			3,068
Deferred income taxes		17			—
Long-term debt		2,115			1,760
Unrealized losses on mark-to-market and hedging instruments		33			54
Other long-term liabilities		226			224
Non-controlling interests		71			95
Commitments and contingent liabilities
Members’ equity:
Members’ interest		2,107			2,107
Retained earnings		153			411
Accumulated other comprehensive loss		(3	)		(8	)
Total members’ equity		2,257			2,510
Total liabilities and members’ equity	$	6,896		$	7,711

See Notes to Consolidated Financial Statements.

F-2

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

Years Ended December 31, 2006 and 2005

(millions)


	2006			2005
Operating revenues:
Sales of natural gas and petroleum products	$	9,137		$	10,011
Sales of natural gas and petroleum products to affiliates		2,813			2,785
Transportation, storage and processing		308			253
Trading and marketing gains (losses)		77			(15	)
Total operating revenues		12,335			13,034
Operating costs and expenses:
Purchases of natural gas and petroleum products		9,322			10,133
Purchases of natural gas and petroleum products from affiliates		789			830
Operating and maintenance		462			447
Depreciation and amortization		284			287
General and administrative		234			195
Gain on sale of assets		(28	)		(2	)
Total operating costs and expenses		11,063			11,890
Operating income		1,272			1,144
Gain on sale of general partner interest in TEPPCO		—			1,137
Equity in earnings of unconsolidated affiliates		20			22
Non-controlling interest in (income) loss		(15	)		1
Interest income		26			26
Interest expense		(145	)		(154	)
Income from continuing operations before income taxes		1,158			2,176
Income tax expense		(23	)		(9	)
Income from continuing operations		1,135			2,167
Income from discontinued operations, net of income taxes		—			3
Net income		1,135			2,170
Other comprehensive income (loss):
Foreign currency translation adjustment		—			(8	)
Canadian business distributed to Duke Energy		—			(70	)
Net unrealized gains on cash flow hedges		5			—
Reclassification of cash flow hedges into earnings		—			1
Total other comprehensive income (loss)		5			(77	)
Total comprehensive income	$	1,140		$	2,093

See Notes to Consolidated Financial Statements.

F-3

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2006 and 2005

(millions)


	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,135		$	2,170
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—			(3	)
Gain from sale of equity investment in TEPPCO		—			(1,137	)
Gain on sale of assets		(28	)		(2	)
Depreciation and amortization		284			287
Equity in earnings of unconsolidated affiliates, net of distributions		—			15
Deferred income tax expense (benefit)		17			(2	)
Non-controlling interest in income (loss)		15			(1	)
Other, net		(3	)		2
Changes in operating assets and liabilities which provided (used) cash:
Accounts receivable		314			(432	)
Inventories		23			(37	)
Net unrealized (gains) losses on mark-to-market and hedging instruments		(1	)		9
Accounts payable		(495	)		910
Accrued interest payable		1			(14	)
Other		(16	)		(12	)
Net cash provided by continuing operations		1,246			1,753
Net cash provided by discontinued operations		—			11
Net cash provided by operating activities		1,246			1,764
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital and acquisition expenditures		(325	)		(212	)
Investments in unconsolidated affiliates		(44	)		(24	)
Distributions received from unconsolidated affiliates		2			—
Purchases of available-for-sale securities		(19,666	)		(17,986	)
Proceeds from sales of available-for-sale securities		20,121			17,260
Proceeds from sales of assets		81			53
Proceeds from sale of general partner interest in TEPPCO		—			1,100
Other		—			9
Net cash provided by continuing operations		169			200
Net cash used in discontinued operations		—			(13	)
Net cash provided by investing activities		169			187
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends and distributions to members		(1,451	)		(2,313	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		—			206
Contribution received from ConocoPhillips		—			398
Payment of debt		(320	)		(607	)
Proceeds from issuing debt		378			408
Loans made to Duke Capital LLC and ConocoPhillips		—			(1,100	)
Repayment of loans by Duke Capital LLC and ConocoPhillips		—			1,100
Net cash (paid to) received from non-controlling interests		(10	)		3
Other		(3	)		(2	)
Net cash used in continuing operations		(1,406	)		(1,907	)
Net cash used in discontinued operations		—			(44	)
Net cash used in financing activities		(1,406	)		(1,951	)
Net increase in cash and cash equivalents		9			—
Cash and cash equivalents, beginning of year		59			59
Cash and cash equivalents, end of year	$	68		$	59

Supplementary cash flow information:
Cash paid for interest (net of amounts capitalized)	$	141		$	163

See Notes to Consolidated Financial Statements.

F-4

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

Years Ended December 31, 2006 and 2005

(millions)


	Members’ Interest		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2005	$	1,709	$	909		$	69		$	2,687
Dividends and distributions		—		(2,414	)		—			(2,414	)
Distribution of Canadian business		—		(254	)		(70	)		(324	)
Contributions		398		—			—			398
Net income		—		2,170			—			2,170
Foreign currency translation adjustment		—		—			(8	)		(8	)
Reclassification of cash flow hedges into earnings		—		—			1			1
Balance, December 31, 2005		2,107		411			(8	)		2,510
Dividends and distributions		—		(1,393	)		—			(1,393	)
Net income		—		1,135			—			1,135
Net unrealized gains on cash flow hedges		—		—			5			5
Balance, December 31, 2006	$	2,107	$	153		$	(3	)	$	2,257

See Notes to Consolidated Financial Statements.

F-5

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2006 and 2005

1. General and Summary of Significant Accounting Policies

Basis of Presentation—DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.

To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.

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

On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical periods included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.

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 (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

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

F-6

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

Acquisitions—We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

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

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

Short-Term and Restricted Investments—We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.

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 Hedging Activities and Financial Instruments—Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.

We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:


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

Cash Flow Hedge	Hedge method^b	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Fair Value Hedge	Hedge method^b	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Normal Purchase or Normal Sale	Accrual method^c	Gross basis upon settlement in the corresponding consolidated statements of operations and comprehensive income category based on purchase or sale
Non-Trading Derivatives	Mark-to-market method ^a	Net basis in trading and marketing gains (losses)

^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 and comprehensive income in trading and marketing gains (losses) during the current period.

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

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

F-7

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

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 accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

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

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

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

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

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

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

Impairment of Unconsolidated Affiliates—We evaluate our 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, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.

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

F-8

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

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

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

•

A significant adverse change in legal factors or business climate;

•

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

•

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

•

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

•

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

•

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

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

We use the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the 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 of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.

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

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

F-9

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the years ended December 31, 2006 and 2005, we paid total dividends of $801 million and $1,925 million, respectively. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and $580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $801 million paid during the year ended December 31, 2006, is comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.

DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

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

Revenue Recognition—We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as trading and marketing of natural gas and NGLs.

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

•

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

•

Percent-of-proceeds/index arrangements—Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, 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 at index prices based on 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. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs.

F-10

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

•

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

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

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

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

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

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

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

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

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

Gas and NGL Imbalance Accounting—Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable—other as of December 31, 2006 and 2005 were imbalances totaling $45 million and $59 million, respectively. Included in the consolidated balance sheets as accounts payable—other, as of December 31, 2006 and 2005 were imbalances totaling $42 million at both periods.

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

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, 2006 and 2005, included in the consolidated balance sheets, totaled $6 million for both periods recorded as other current liabilities, and totaled $6 million and $7 million, respectively, recorded as other long-term liabilities.

Stock-Based Compensation—Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s,

F-11

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.

Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for 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 unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.

Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board, or APB, Opinion No. 25, or APB 25, “Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board, or FASB, Interpretation No. 44, or FIN 44, “Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense was measured as the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under EITF Issue No. 96-18, or EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.

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

We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for the prior periods presented in these consolidated financial statements have not been restated. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.

F-12

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

We recorded stock-based compensation expense for the years ended December 31, 2006 and 2005 as follows, the components of which are further described in Note 13:


	Year Ended December 31,
	2006		2005
	(millions)
Performance awards	$	4	$	3
Phantom awards		4		2

Total	$	8	$	5

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


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

Pro forma net income	$	2,170

Accounting for Sales of Units by a Subsidiary—In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheets. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

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

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

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

SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

F-13

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

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

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

EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

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

2. Acquisitions and Dispositions

Acquisitions

Acquisition of Various Gathering, Transmission and Processing Assets—In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.

Acquisition of Additional Equity Interests—In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.

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

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

F-14

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

Dispositions

Disposition of Various Gathering, Transmission and Processing Assets—In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified certain of these assets as held for sale, recorded in other non-current assets, consisting primarily of property, plant and equipment totaling $58 million at December 31, 2005. Assets at one location, totaling $48 million as of December 31, 2005, were sold in the first quarter of 2006 for $76 million and we recognized a gain of $28 million. Assets at another location, totaling $9 million as of December 31, 2005, were sold in the first quarter of 2006 for $9 million and we recognized no gain or loss.

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

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

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

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

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


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

Total assets	$	372

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

Total liabilities	$	48

Net assets of Canadian business distributed to Duke Energy	$	324

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

F-15

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

There were no assets accounted for as discontinued operations for the year ended December 31, 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005:


	2005
	(millions)
Operating revenues	$	35

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

Income from discontinued operations	$	3

3. Agreements and Transactions with Affiliates

The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging instruments with affiliates as of December 31:


	2006		2005
	(millions)
Duke Energy:
Unrealized gains on mark-to-market and hedging instruments—current	$	—	$	18
Unrealized gains on mark-to-market and hedging instruments—non-current	$	—	$	19
Unrealized losses on mark-to-market and hedging instruments—current	$	—	$	(20	)
Unrealized losses on mark-to-market and hedging instruments—non-current	$	—	$	(20	)
ConocoPhillips:
Unrealized gains on mark-to-market and hedging instruments—current	$	1	$	9
Unrealized losses on mark-to-market and hedging instruments—current	$	—	$	(4	)

The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the years ended December 31:


	2006		2005
	(millions)
Duke Energy:
Sales of natural gas and petroleum products to affiliates	$	41	$	109
Transportation, storage and processing	$	18	$	2
Purchases of natural gas and petroleum products from affiliates	$	137	$	130
Operating and general and administrative expenses	$	30	$	44
Interest income	$	—	$	8

ConocoPhillips (a):
Sales of natural gas and petroleum products to affiliates	$	2,677	$	2,513
Transportation, storage and processing	$	12	$	11
Purchases of natural gas and petroleum products from affiliates	$	492	$	556
General and administrative expenses	$	5	$	—

Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	95	$	163
Transportation, storage and processing	$	20	$	20
Purchases of natural gas and petroleum products from affiliates	$	160	$	144

(a)	Includes ConocoPhillips’ 50% owned equity method investment, CP Chem

Spectra Energy and Duke Energy

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

F-16

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.

Included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are other receivables of $8 million and $39 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. During the years ended December 31, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

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

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

ConocoPhillips

Long-term NGLs Purchases Contract and Transactions—We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has 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 CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

Transactions with other unconsolidated affiliates

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

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

Estimates related to affiliates

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

F-17

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

4. Marketable Securities

Short-term and restricted investments—At December 31, 2006 and 2005, we had $437 million and $627 million, respectively, of short-term investments. These instruments are classified as available-for-sale securities under SFAS 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as the interest rates re-set on a daily, weekly or monthly basis.

In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash was invested in financial instruments as described above. Under the terms of the amended and restated LLC Agreement, however, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. As this cash was to be used to acquire non-current assets, we had $0 and $264 million, respectively, classified as a long-term asset, as restricted investments, on the consolidated balance sheets at December 31, 2006 and 2005. At December 31, 2006 and 2005, we had restricted investments of $102 million and $100 million, respectively, consisting of collateral for DCP Partners’ term loan.

5. Inventories

Inventories by category were as follows as of December 31:


	2006		2005
	(millions)
Natural gas held for resale	$	34	$	43
NGLs		53		67

Total inventories	$	87	$	110

6. Property, Plant and Equipment

Property, plant and equipment by classification was as follows as of December 31:


	Depreciable Life	2006			2005
		(millions)
Gathering	15 -30 years	$	2,641		$	2,503
Processing	25 -30 years		1,904			1,840
Transportation	25 -30 years		1,217			1,223
Underground storage	20 -50 years		119			103
General plant	3 - 5 years		146			138
Construction work in progress			203			108

			6,230			5,915
Accumulated depreciation			(2,361	)		(2,079	)

Property, plant and equipment, net		$	3,869		$	3,836

Depreciation expense for 2006 and 2005 was $275 million and $278 million, respectively. Interest capitalized on construction projects in 2006 and 2005, was approximately $3 million and $2 million, respectively. At December 31, 2006, we had non-cancelable purchase obligations of approximately $27 million for capital projects expected to be completed in 2007. In addition, property, plant and equipment includes $10 million and $13 million of non-cash additions for the years ended December 31, 2006 and 2005, respectively.

F-18

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

7. Goodwill and Other Intangibles

The changes in the carrying amount of goodwill are as follows for the years ended December 31:


	2006		2005
	(millions)
Goodwill, beginning of period	$	421	$	452
Purchase price adjustments		—		(11	)
Foreign currency translation adjustments		—		(2	)
Distribution of Canadian business to Duke Energy		—		(18	)

Goodwill, end of period	$	421	$	421

We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.

We completed our annual goodwill impairment test as of August 31, 2006. We also tested goodwill for impairment in July 2005 upon the distribution of substantially all of our Canadian business to Duke Energy, in conjunction with the 50-50 Transaction. These goodwill impairment tests were performed by comparing our reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the years ended December 31, 2006 and 2005.

During 2005, we recorded an adjustment to properly account for deferred taxes established as a result of purchase business combinations that occurred during 2001. As a result of this adjustment, goodwill and deferred income tax liabilities decreased by approximately $11 million and $3 million, respectively, and property, plant and equipment, net, increased by $8 million.

In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. Included in the distribution was $18 million of goodwill, which was determined based on the relative fair value of the Canadian business to the fair value of the Natural Gas Services reporting unit.

The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows for the years ended December 31:


	2006			2005
	(millions)
Commodity sales and purchases contracts	$	132		$	130
Accumulated amortization		(74	)		(64	)

Commodity sales and purchases contracts, net	$	58		$	66

During the years ended December 31, 2006 and 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.

Estimated amortization for these contracts for the next five years and thereafter is as follows:


	Estimated Amortization
	(millions)
2007	$	8
2008		8
2009		8
2010		8
2011		7
Thereafter		19

Total	$	58

F-19

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

8. Investments in Unconsolidated Affiliates

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


	2006 Ownership		December 31,
	2006 Ownership		2006		2005
			(millions)
Discovery Producer Services LLC	40.00	%	$	114	$	102
Main Pass Oil Gathering Company	66.67	%		47		13
Sycamore Gas System General Partnership	48.45	%		12		13
Mont Belvieu I	20.00	%		11		12
Tri-States NGL Pipeline, LLC	16.67	%		9		9
Black Lake Pipe Line Company	50.00	%		6		6
Other unconsolidated affiliates	Various			5		14

Total investments in unconsolidated affiliates			$	204	$	169

Discovery Producer Services LLC—Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

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

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 $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

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 $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.

Tri-States NGL Pipeline, LLC—Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

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

Fox Plant, LLC—In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary. Fox Plant, LLC is included in other unconsolidated affiliates in the above table as of December 31, 2005.

F-20

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

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

Equity in earnings of unconsolidated affiliates amounted to the following for the years ended December 31:


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

Total equity in earnings of unconsolidated affiliates	$	20		$	22

The following summarizes combined financial information of unconsolidated affiliates for the years ended and as of December 31:


	2006		2005
	(millions)
Income statement:
Operating revenues	$	322	$	328
Operating expenses	$	287	$	312
Net income	$	42	$	18
Balance sheet:
Current assets	$	115	$	133
Non-current assets		724		740
Current liabilities		61		81
Non-current liabilities		7		6

Net assets	$	771	$	786

9. Estimated Fair Value of Financial Instruments

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


	December 31, 2006						December 31, 2005
	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
	(millions)
Short-term investments	$	437		$	437		$	627		$	627
Restricted investments		102			102			364			364
Accounts receivable		1,272			1,272			1,636			1,636
Accounts payable		(1,624	)		(1,624	)		(2,119	)		(2,119	)
Net unrealized gains and losses on mark-to-market and hedging instruments		22			22			14			14
Current maturities of long-term debt		—			—			(300	)		(302	)
Long-term debt		(2,115	)		(2,258	)		(1,760	)		(1,942	)

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

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

F-21

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

10. Asset Retirement Obligations

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

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

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, for the years ended December 31:


	2006			2005
	(millions)
Balance as of January 1	$	50		$	57
Accretion expense		3			3
Liabilities incurred		—			1
Liabilities settled		(1	)		—
Distribution of Canadian business to Duke Energy		—			(10	)
Other		—			(1	)

Balance as of December 31	$	52		$	50

11. Financing

Long-term debt was as follows at December 31:


	Principal/Discount
	2006			2005
	(millions)
Debt securities:
Issued November 2001, interest at 5.750% payable semiannually, due November 2006	$	—		$	300
Issued August 2000, interest at 7.875% payable semiannually, due August 2010		800			800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011		250			250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015		200			200
Issued August 2000, interest at 8.125% payable semiannually, due August 2030		300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036		300			—
DCP Partners’ credit facility revolver, weighted average interest rate of 5.86% at December 31, 2006, due December 2010		168			110
DCP Partners’ credit facility term loan, interest rate of 5.47% at December 31, 2006, due December 2010		100			100
Fair value adjustments related to interest rate swap fair value hedges (a)		4			7
Unamortized discount		(7	)		(7	)
Current portion of long-term debt		—			(300	)

Long-term debt	$	2,115		$	1,760

(a)	See Note 12 for further discussion.

Debt Securities—In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on

F-22

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.

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

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

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

Credit Facilities with Financial Institutions—On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in these financial statements as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility. As of December 31, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.

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

On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006 and 2005, there was $168 million and $110 million, respectively, outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of December 31, 2006, and there were no letters of credit outstanding at December 31, 2005. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, 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 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

F-23

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:


	Debt Maturities
	(millions)
2010	$	1,068
2011		250
Thereafter		804

		2,122
Unamortized discount		(7	)

Long-term debt	$	2,115

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

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

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

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

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

As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.

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.

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

Commodity hedging strategies—Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.

Commodity cash flow hedges—We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.

For the year ended December 31, 2006, amounts recognized as comprehensive income in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were gains of $4 million, and amounts recognized for the effects of any ineffectiveness were insignificant for the year ended December 31, 2006. For the year ended December 31, 2005, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. During the year ended December 31, 2006, we reclassified $1 million in net gains (net of minority interest of $2 million) to the consolidated statements of operations and comprehensive income as a result of settlements. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006, and was insignificant at December 31, 2005. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

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

For the years ended December 31, 2006 and 2005, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and, therefore, did not recognize an associated gain or loss.

Interest rate cash flow hedges—During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the accompanying consolidated balance sheets. For the year ended December 31, 2006, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were not significant, and there was no ineffectiveness recorded for the year ended December 31, 2006. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; 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.

Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The amount amortized to interest expense during the years ended December 31, 2006 and 2005, was $1 million for both periods. The deferred balance was a loss of $7

F-25

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

million and $8 million at December 31, 2006 and 2005, respectively. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.

Interest rate fair value hedges—In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.

In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2006 and 2005, the fair value of the interest rate swaps was a $4 million and $8 million asset, respectively, which is included in the consolidated balance sheets as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.

Commodity derivatives—trading and marketing—Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.

13. Stock-Based Compensation

DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan—Relative Performance Units—RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the RPUs for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:


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

Outstanding at December 31, 2006	44,080	$	42.89	$	50.78

Expected to vest	15,869	$	42.89	$	50.78

Strategic Performance Units—SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the SPUs for the year ended December 31, 2006, was approximately $1 million. At December 31, 2006 there was

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:


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

Outstanding at December 31, 2006	84,960	$	42.92	$	50.78

Expected to vest	65,949	$	42.92	$	50.78

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

Phantom Units—Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:


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

Outstanding at December 31, 2006	17,460	$	42.95	$	50.78

Expected to vest	14,143	$	42.95	$	50.78

DCP Partners’ Phantom Units—The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. Expense related to the DCP Partners’ Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:


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

Outstanding at December 31, 2006	47,750	$	28.60	$	34.55

Expected to vest	34,920	$	28.60	$	34.55

During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.

DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan—Performance Units—Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the Performance Units for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:


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

Outstanding at December 31, 2006	23,090		$	26.96	$	34.55

Expected to vest	23,090		$	26.96	$	34.55

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

Phantom Units—Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:


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

Outstanding at December 31, 2006	24,700		$	24.05	$	34.55

Expected to vest	24,700		$	24.05	$	34.55

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

All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash 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. During the year ended December 31, 2006, no awards were vested or settled.

Duke Energy 1998 Plan—Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. 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 ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.

F-28

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

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. Vesting periods range from immediate to four years with a maximum option term of 10 years. Effective July 1, 2005, these options were accounted for in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.

The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.


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

Outstanding at December 31, 2006	2,101,062		$	30.89	4.1	$	12

Exercisable at December 31, 2006	1,941,212		$	32.30	4.0	$	9
Expected to vest	155,630		$	13.77	6.2	$	3

The total intrinsic value of options exercised during the year ended December 31, 2006 and 2005, was approximately $3 million and $2 million, respectively. As of December 31, 2006, all compensation expense related to these awards has been recognized.

There were no options granted during the years ended December 31, 2006 or 2005.

Stock-Based Performance Awards—Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. Duke Energy awarded 160,910 shares during the year ended December 31, 2005. There were no stock-based performance awards granted during the year ended December 31, 2006.

The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:


	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	342,453		$	23.88
Forfeited	(40,835	)	$	23.85

Outstanding at December 31, 2006	301,618		$	23.90	$	33.21

Expected to vest	289,161		$	23.90	$	33.21

As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.

Phantom Stock Awards—Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 128,850 shares during the year ended December 31, 2005. There were no phantom stock awards granted during the year ended December 31, 2006.

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:


	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	241,216		$	24.22
Vested	(54,150	)	$	23.90
Forfeited	(22,378	)	$	24.29

Outstanding at December 31, 2006	164,688		$	24.34	$	33.21

Expected to vest	157,886		$	24.34	$	33.21

The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 and 2005 was approximately $2 million and less than $1 million, respectively. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.

Other Stock Awards—Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy granted 3,000 other stock awards during the year ended December 31, 2005. There were no other stock awards granted during the year ended December 31, 2006.

The following table summarizes information about other stock awards activity during the year ended December 31, 2006:


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

Outstanding at December 31, 2006	21,600		$	21.73	$	33.21

Expected to vest	20,038		$	21.73	$	33.21

The total fair value of the other stock awards that vested during the years ended December 31, 2006 and 2005 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.

14. Benefits

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

We offer certain eligible executives the opportunity to participate in the 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.

15. Income Taxes

We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

is included in our income tax expense, along with state, local, franchise, and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.

In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.

As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.

The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheets as of December 31, 2006, and as a non-cash offset to income tax expense in the consolidated statements of operations and comprehensive income for the year ended December 31, 2006.

Income tax expense consists of the following for the years ended December 31:


	2006		2005
	(millions)
Current:
Federal	$	5	$	9
State		1		2
Deferred:
Federal		—		—
State		17		(2	)

Total income tax expense	$	23	$	9

Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.

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

16. Commitments and Contingent Liabilities

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

In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing

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DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.

Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.

General Insurance—In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.

During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are $25 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $3 million and $28 million, respectively, from an insurance provider that is a subsidiary of Duke Energy.

During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006 are $21 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $2 million and $5 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006. The balance at December 31, 2005, was not significant. Based on recent negotiations, we have reclassified a portion of these hurricane insurance receivables as non-current at December 31, 2006.

During the years ended December 31, 2006 and 2005, we recorded business interruption insurance recoveries related to these hurricanes of $1 million and $3 million, respectively, in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, 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.

F-32

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated results of operations, cash flows or financial position.

Other Commitments and Contingencies—We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $37 million and $36 million in 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:


	Minimum Rental Payments
	(millions)
2007	$	25
2008		19
2009		14
2010		14
2011		12
Thereafter		39

Total gross payments		123
Sublease receipts		(2	)

Total net payments	$	121

17. Guarantees and Indemnifications

In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.

We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At both December 31, 2006 and 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

18. Subsequent Events

In March 2007, DCP Midstream Partners entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation, or Anadarko, for approximately $180 million, subject to customary closing conditions and certain regulatory approvals. DCP Midstream Partners paid an earnest deposit of $9 million when they entered into this agreement. If Anadarko terminates because DCP Midstream Partners materially breaches their representations, warranties or covenants under this agreement, Anadarko may retain this earnest deposit as liquidated damages. This deposit will be applied against the purchase price at the closing of this transaction, which is expected to occur in the second quarter of 2007. The remaining purchase price is expected to be funded by the issuance of DCP Midstream Partners’ partnership units and by proceeds from DCP Midstream Partners’ credit facility.

F-33

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Years Ended December 31, 2006 and 2005

On January 24, 2007, DCP Partners announced the declaration of a cash distribution of $0.43 per unit, payable on February 14, 2007, to unitholders of record on February 7, 2007.

On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.

On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.

F-34

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended December 31, 2006 and 2005


			Increases
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts			Deductions			Balance at End of Period
					(b)			(c)
	($ in millions)
December 31, 2006
Allowance for doubtful accounts	$	4	$	—	$	—		$	(1	)	$	3
Environmental		13		3		—			(4	)		12
Litigation		5		6		—			(2	)		9
Other (a)		6		—		—			(2	)		4

	$	28	$	9	$	—		$	(9	)	$	28

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

	$	37	$	18	$	—		$	(27	)	$	28

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

(b)	Consists of other contingency and litigation reserves reclassified between accounts.

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

F-35

EXHIBIT INDEX

Exhibits filed with the original Form 10-K on March 1, 2007 are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**). Portions of the exhibit designated by a triple asterisk (***), which were filed with the original Form 10-K on March 1, 2007, were omitted and were filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934. Exhibits filed herewith are designated by a quadruple asterisk (****).


Exhibit Number
2.1		Agreement and Plan of Merger, dated as of May 8, 2005, as amended as of July 11, 2005, as of October 3, 2005 and as of March 30, 2006, by and among the registrant, Duke Energy Corporation, Cinergy Corp., Deer Acquisition Corp., and Cougar Acquisition Corp. (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 2-1).

2.2		Amended and Restated Combination Agreement dated as of September 20, 2001, among Duke Energy Corporation, 3058368 Nova Scotia Company, 3946509 Canada Inc. and Westcoast Energy Inc. (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit 10-7).

2.3		Separation and Distribution Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 2.1).

3.1		Amended and restated Certificate of Incorporation (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 3-1).

3.2		Amended and Restated By-Laws of registrant (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 3.2).

4		Rights Agreement, dated as of December 17, 1998, between the registrant and The Bank of New York, as Rights Agent (filed with the Form 8-K of Duke Energy Carolinas, LLC, dated February 11, 1999, File No. 1-4928, as Exhibit 4-1).

4.1		Amendment No. 1, dated as of May 8, 2005, to the Rights Agreement, dated as of December 17, 1998, between the registrant and The Bank of New York, as rights agent (filed with the Form 8-K of Duke Energy Carolinas, LLC, May 12, 2005, File No. 1-4928, as Exhibit 4-1).

10.1		Purchase and Sale Agreement dated as of February 24, 2005, by and between Enterprise GP Holdings LP and Duke Energy Field Services, LLC (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-25).

10.2		Term Sheet Regarding the Restructuring of Duke Energy Field Services LLC dated as of February 23, 2005, between Duke Energy Corporation and ConocoPhillips (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-26).

10.3		Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of May 26, 2005 (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-4).

10.3.1		First Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of June 30, 2005 (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-4.1).

10.3.2		Second Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of July 11, 2005 (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-4.2).

10.4		Purchase and Sale Agreement dated as of January 8, 2006, by and among Duke Energy Americas, LLC, and LSP Bay II Harbor Holding, LLC (filed with the Form 10-Q of the registrant for the quarter ended March 31, 2006, File No. 1-32853, as Exhibit 10.2).


Exhibit Number
10.4.1		Amendment to Purchase and Sale Agreement, dated as of May 4, 2006, by and among Duke Energy Americas, LLC, LS Power Generation, LLC (formerly known as LSP Bay II Harbor Holding, LLC), LSP Gen Finance Co, LLC, LSP South Bay Holdings, LLC, LSP Oakland Holdings, LLC, and LSP Morro Bay Holdings, LLC ((filed with the Form 10-Q of the registrant for the quarter ended March 31, 2006, File No. 1-32853, as Exhibit 10.2.1).

10.5		Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation, dated as of July 5, 2005 (filed with the Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2005, File No. 1-4928, as Exhibit 10.5).

10.6		Limited Liability Company Agreement of Gulfstream Management & Operating Services, LLC dated as of February 1, 2001 between Duke Energy Gas Transmission Corporation and Williams Gas Pipeline Company (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2002, File No.1-4928, as Exhibit 10-18).

10.7		Formation Agreement between PanEnergy Trading and Market Services, Inc. and Mobil Natural Gas, Inc. dated May 29, 1996 (filed with Form 10-Q of PanEnergy Corp for the quarter ended June 30, 1996, File No. 1-8157, as Exhibit 2).

10.8***		Master Transaction Agreement by and among Duke Energy Marketing America, LLC, Duke Energy North America, LLC, Duke Energy Trading and Marketing, L.L.C., Duke Energy Marketing Limited Partnership, Engage Energy Canada, L.P. and Barclay Bank PLC, dated as of November 17, 2005 (filed with the Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2005, File No. 1-4928, as Exhibit 10.8).

10.9		$800,000,000 364-Day Credit Agreement dated as of June 29, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank, PLC, as Syndication Agent (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-3).

10.10		$600,000,000 Amended and Restated Credit Agreement dated as of June 30, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-2).

10.11		$500,000,000 Amended and Restated Credit Agreement dated as of June 30, 2005, among the registrant, the banks listed therein, Citibank N.A., as Administrative Agent, and Bank of America, N.A., as Syndication Agent (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-1).

10.12		Loan Agreement dated as of February 25, 2005 between Duke Energy Field Services, LLC and Duke Capital LLC (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended March 31, 2005, File No. 1-4928, as Exhibit 10-3).

10.13		Accelerated Share Acquisition Plan, dated March 18, 2005, between registrant and Merrill Lynch International (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended March 31, 2005, File No. 1-4928, as Exhibit 10-4).

10.14**		Directors’ Charitable Giving Program (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 1992, File No. 1-4928, as Exhibit 10-P).

10.14.1**		Amendment to Directors’ Charitable Giving Program dated June 18, 1997 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.1).

10.14.2**		Amendment to Directors’ Charitable Giving Program dated July 28, 1997 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.2).

10.14.3**		Amendment to Directors’ Charitable Giving Program dated February 18, 1998 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.3).

10.15**		Duke Energy Corporation 1998 Long-Term Incentive Plan, as amended (filed as Exhibit 1 to Schedule 14A of Duke Energy Carolinas, LLC, March 28, 2003, File No. 1-4928).


Exhibit Number
10.16**		Duke Energy Corporation Executive Short-Term Incentive Plan (filed as Exhibit 2 to Schedule 14A of Duke Energy Carolinas, LLC, March 28, 2003, File No. 1-4928).

10.17**		Duke Energy Corporation Executive Savings Plan, as amended and restated (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-6).

10.17.1**		Amendment No. 1 to the Duke Energy Corporation Executive Savings Plan, dated October 27, 2004, effective December 31, 2004. (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-6.1).

10.17.2*		Amendment to the Duke Energy Corporation Executive Savings Plan, effective December 18, 2006.

10.17.3*		Amendment to the Duke Energy Corporation Executive Savings Plan I & II, effective December 19, 2006.

10.18**		Duke Energy Corporation Executive Cash Balance Plan (filed with Form 10-K of TEPPCO Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10-8).

10.18.1**		Amendment No. 1 to the Duke Energy Corporation Executive Cash Balance Plan, dated August 26, 1999 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.1).

10.18.2**		Amendment No. 2 to the Duke Energy Corporation Executive Cash Balance Plan, dated March 6, 2000 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.2).

10.18.3**		Amendment No. 3 to the Duke Energy Corporation Executive Cash Balance Plan, dated December 21, 2000 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.3).

10.18.4**		Amendment No. 4 to the Duke Energy Corporation Executive Cash Balance Plan, dated October 27, 2004, effective December 31, 2004 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.4).

10.18.5*		Amendment to the Duke Energy Corporation Executive Cash Balance Plan, effective December 1, 2006.

10.18.6*		Amendment to the Duke Energy Corporation Executive Cash Balance Plan I & II, effective December 31, 2006.

10.19**		Duke Energy Corporation Retirement Benefit Equalization Plan (filed with Form 10-K of TEPPCO Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10.9).

*10.19.1		Amendment to the Duke Energy Corporation Retirement Benefit Equalization Plan, effective December 21, 2006.

10.20**		Form of Key Employee Severance Agreement and Release between Duke Energy Corporation and certain key executives (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 1999, File No. 1-4928, as Exhibit 10-BB).

10.21**		Form of Change in Control Agreement between Duke Energy Corporation and certain key executives (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 1999, File No. 1-4928, as Exhibit 10-CC).

10.22**		Form of Change in Control Agreement between Duke Energy Corporation and certain key executives dated as of July 1, 2005 (filed with Form 8-K of Duke Energy Carolinas, LLCdated August 24, 2005, File No. 1-4928, as Exhibit 10-1).

10.23**		Employment Agreement dated November 2003 between Paul M. Anderson and Duke Energy Corporation (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-18).

10.23.1**		First Amendment to Employment Agreement dated March 9, 2004 between Paul M. Anderson and Duke Energy Corporation (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-18.1).

10.23.2**		Performance Award Agreement dated November 17, 2003, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan, by and between Duke Energy Corporation and Paul M. Anderson (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.2).

10.23.3**		Phantom Stock Agreement dated November 17, 2003, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan, by and between Duke Energy Corporation and Paul M. Anderson (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.3).


Exhibit Number
10.23.4**		Non-Qualified Option Agreement dated as of November 17, 2003 pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan, by and between Duke Energy Corporation and Paul M. Anderson (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.4).

10.23.5**		Second Amendment to Employment Agreement, dated as of April 4, 2006, by and among Paul M. Anderson, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation) and Duke Energy Corporation (subsequently renamed Duke Energy Carolinas, LLC) (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.5).

10.24**		Supplemental Compensation Agreement dated June 17, 1997 between Duke Power Company and Dr. Ruth G. Shaw (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-19).

10.24.1**		Severance and Retention Agreement between Duke Energy Corporation and Ruth Shaw, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.7).

10.24.2**		Severance and Consulting Agreement between Duke Energy Corporation and Ruth Shaw, dated October 24, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, October 27, 2006, as Exhibit 10.2).

10.25**		Resolution of Board of Directors, February 22, 2005, Approving Award of Phantom Stock to Nonemployee Directors (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended March 31, 2005, File No. 1-4928, as Exhibit 10-9).

10.26**		Resolution of Board of Directors, May 12, 2005, Approving Change to Retainer and Attendance Fees for Non-Employee Directors (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-5).

10.27**		Form of Performance Award Agreement dated February 28, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and each of Fred J. Fowler, David L. Hauser, Jimmy W. Mogg and Ruth G. Shaw (filed with the Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, February 28, 2006, as Exhibit 10-1).

10.28**		Form of Phantom Stock Award Agreement dated February 28, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and each of Fred J. Fowler, David L. Hauser, Jimmy W. Mogg and Ruth G. Shaw (filed with the Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, February 28, 2005, as Exhibit 10-2).

10.29**		Form of Phantom Stock Award Agreement dated as of May 11, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and Jimmy W. Mogg. (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-6).

10.30**		Form of Phantom Stock Award Agreement dated as of May 12, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and nonemployee directors (filed in Form 8-K of Duke Energy Carolinas, LLC, May 17, 2005, File No. 1-4928, as Exhibit 10-1).

10.31**		Agreement between Duke Energy Corporation and Jimmy W. Mogg relating to certain retirement benefits, consisting of letter agreements dated May 25, 1995, August 4, 2001 and March 29, 2004 (filed with Form 10-K of Duke Energy Carolinas, LLCfor the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-23).

10.32**		First Amendment to Key Employee Severance Agreement and General Release between Duke Energy Corporation and Richard J. Osborne, dated August 21, 2004 (filed with Form 10-Q of Duke Energy Carolinas, LLCfor the quarter ended October 31, 2004, File No. 1-4928, as Exhibit 10-2).

10.33**		Certification of Chairman and Chief Executive Officer 2004 Performance Goals (filed in Form 8-K of Duke Energy Carolinas, LLC, February 28, 2005, File No. 1-4928, as item 1 of Item 1.01).

10.34**		Approval of Payment of 2004 Executive Officer Short-Term Incentives (filed in Form 8-K of Duke Energy Carolinas, LLC, February 28, 2005, File No. 1-4928, as item 2 of Item 1.01).
10.35**		Establishment of Chairman and Chief Executive Officer 2005 Performance Goals (filed in Form 8-K of Duke Energy Carolinas, LLC, February 28, 2005, File No. 1-4928, as item 3 of Item 1.01).


Exhibit Number

10.35.1**		Certification of Chairman and Chief Executive Officer 2005 Performance Goals (filed with Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, March 3, 2006, as item 1 of Item 1.01).

10.36**		Establishment of Financial Measure Portion of Chairman and Chief Executive Officer 2006 Performance Goals (filed in Form 8-K of Duke Energy Carolinas, LLC, December 22, 2005, File No. 1-4928, as item 2 of Item 1.01).

10.37**		2005 Executive Officer Base Salaries, Short-Term Incentive Opportunities and Long-Term Incentive Opportunities (filed in Form 8-K of Duke Energy Carolinas, LLC, February 28, 2005, File No. 1-4928, as item 4 of Item 1.01).

10.38**		2006 Executive Officer Base Salaries and Short-Term Incentive Opportunities (filed in Form 8-K of Duke Energy Carolinas, LLC, December 22, 2005, File No. 1-4928, as item 1 of Item 1.01).

10.38.1**		Final Approval of 2006 Executive Officer Financial Performance Target for Short-Term Incentive Opportunity (filed with Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, March 3, 2006, as item 3 of Item 1.01).

10.39		Approval of Payment of 2005 Executive Officer Short-Term Incentives (filed with Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, March 3, 2006, as item 2 of Item 1.01).

10.40		Form of Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 10.1).

10.41		Form of Performance Share Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 10.2).

10.42**		Employment Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.1).

10.42.1**		Performance Award Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.2).

10.42.2**		Phantom Stock Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.3).

10.42.3**		Stock Option Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.4).

10.43**		Retention Award Agreement between Duke Energy Corporation and David L. Hauser, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.6).

10.44**		Summary of Director Compensation (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.13).

10.45**		Form Phantom Stock Award Agreement and Election to Defer (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 16, 2006, as Exhibit 10.1).

10.46		Agreements with Piedmont Electric Membership Corporation, Rutherford Electric Membership Corporation and Blue Ridge Electric Membership Corporation to provide wholesale electricity and related power scheduling services from September 1, 2006 through December 31, 2021 (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.15).

10.47		Agreement with Dynegy Inc. and Rockingham Power, L.L.C. to acquire an approximately 825 megawatt power plant located in Rockingham County, N.C. for approximately $195 million (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 25, 2006, as Exhibit 10.1).

10.48		Purchase and Sale Agreement by and among Cinergy Capital & Trading, Inc., as Seller, and Fortis Bank, S.A./N.V., as Buyer, dated as of June 26, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, June 30, 2006, as Exhibit 10.1).

10.49		Amended and Restated Credit Agreement, dated June 29, 2006, among Cinergy Corp., CG&E, PSI, ULH&P, The Banks Listed Herein, Barclays Bank PLC, as Administrative Agent, and JPMorgan Chase Bank, N.A., as Syndication Agent (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.18).


Exhibit Number
10.50		Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Capital LLC, The Banks Listed Herein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.19).

10.51		Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Energy Carolinas, LLC, The Banks Listed Herein, Citibank N.A., as Administrative Agent, and Banc of America, N.A., as Syndication Agent (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.20).

10.52**		Form of Amendment to Performance Award Agreement and Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as Exhibit 10.1).

10.53**		Form of Amendment to Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as Exhibit 10.2).

10.54		Formation and Sale Agreement by and among Duke Ventures, LLC, Crescent Resources, LLC, Morgan Stanley Real Estate Fund V U.S. L.P., Morgan Stanley Real Estate Fund V Special U.S., L.P., Morgan Stanley Real Estate Investors V U.S., L.P., MSP Real Estate Fund V, L.P., and Morgan Stanley Strategic Investments, Inc., dated as of September 7, 2006 (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2006, File No. 1-32853, as Exhibit 10.3).

10.55		Amendment No. 1 to Credit Agreement (“Amendment”) dated as of February 28, 2006, by and among Duke Energy Carolinas, LLC (formerly known as Duke Energy Corporation), the banks listed therein, Citibank N.A., as Administrative Agent, and Bank of America, N.A., as Syndication Agent (filed with Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, March 30, 2006, as Exhibit 10.1).

10.56		Fifteenth Supplemental Indenture, dated as of April 3, 2006, among the registrant, Duke Energy and JPMorgan Chase Bank, N.A. (as successor to Guaranty Trust Company of New York), as trustee (the “Trustee”), supplementing the Senior Indenture, dated as of September 1, 1998, between Duke Energy Carolinas, LLC (formerly Duke Energy Corporation) and the Trustee (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.1).

10.57		Amendment No. 1 to the Twelfth Supplemental Indenture, dated as of April 1, 2006 (“Amendment No. 1”), among the registrant, Duke Energy and the Trustee, which amends the Twelfth Supplemental Indenture, dated as of May 7, 2003, between the registrant and the Trustee, pursuant to which the Convertible Notes were issued (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.3).

10.58**		Duke Energy Corporation 2006 Long-Term Incentive Plan (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, October 27, 2006, as Exhibit 10.1).

10.59		Tax Matters Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.1).

10.60		Transition Services Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.2).

10.61		Employee Matters Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.3).

10.62**		Agreement between Duke Energy Corporation and Fred J. Fowler, dated December 19, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 22, 2006, as Exhibit 10.1).

10.63*		Amendment to the Duke Energy Corporation Directors’ Savings Plan I & II, effective December 19, 2006.

10.64*		Amendment to the Cinergy Corp. Excess Pension Plan, effective January 1, 2007.

10.65*		Amendment to the Cinergy Corp. 401(k) Excess Plan, effective December 18, 2006.


Exhibit Number
10.66*		Amendment to the Cinergy Corp. Excess Profit Sharing Plan, effective December 19, 2006.

10.67*		Amendment to the Cinergy Corp. 401(k) Excess Plan, effective December 19, 2006.

10.68*		Amendment to the Cinergy Corp. Directors’ Deferred Compensation Plan, effective December 19, 2006.

*12		Computation of Ratio of Earnings to Fixed Charges.

*21		List of Subsidiaries.

*23.1		Consent of Independent Registered Public Accounting Firm.

23.1****		Consent of Independent Auditors.

*23.2		Consent of Independent Registered Public Accounting Firm.

*24.1		Power of attorney authorizing David L. Hauser and others to sign the annual report on behalf of the registrant and certain of its directors and officers.

*24.2		Certified copy of resolution of the Board of Directors of the registrant authorizing power of attorney.

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.

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.