Duke Energy Carolinas 10-K/A 2005 FY Annual report (amended)

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, 2005 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 1-4928

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

North Carolina	56-0205520
(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.
Preference Stock Purchase Rights	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 ¨ Nox

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 and (2) has been subject to such filing requirements for the past 90 days. Yesx 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, 2005	$	27,467,000,000
Number of shares of Common Stock, without par value, outstanding at February 28, 2006		928,185,106

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, 2005 is being filed for the purpose of providing separate audited financial statements of 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, 2005, and does not reflect events occurring after the original filing date of March 3, 2006.

Item 15. Exhibits and Financial Statement Schedule

(a) Financial Statements

The following financial statements and related notes were filed as part of Duke Energy’s Form 10-K filed March 3, 2006:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003

Consolidated Balance Sheets as of December 31, 2005 and 2004

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003

Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income (Loss) 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 3, 2006:

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:

Audited Financial Statements of Duke Energy Field Services, LLC for the year ended December 31, 2005

Consolidated Financial Statement Schedule II of Duke Energy Field Services, LLC—Valuation and Qualifying Accounts and Reserves for the Year Ended December 31, 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.

(c) Exhibits

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 31, 2006

DUKE ENERGY CORPORATION (Registrant)
By:	/S/    PAUL M. ANDERSON
	Paul M. Anderson Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

(i) Principal executive officer:

Paul M. Anderson

Chairman of the Board and Chief Executive Officer

(ii) Principal financial officer:

David L. Hauser

Group Vice President and Chief Financial Officer

(iii) Principal accounting officer:

Steven K. Young

Vice President and Controller

(iv) A majority of the Directors:

Roger Agnelli

Paul M. Anderson

William Barnet, III

G. Alex Bernhardt, Sr.

William T. Esrey

Ann Maynard Gray

James H. Hance Jr.

Dennis R. Hendrix

A. Max Lennon

James G. Martin

Michael E.J. Phelps

James T. Rhodes

Date: March 31, 2006

David L. Hauser, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.

By:	/s/    DAVID L. HAUSER
	Attorney-In-Fact

Duke Energy Field Services, LLC

Consolidated Financial Statements for the

Year ended December 31, 2005

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

Duke Energy Field Services, LLC

Denver, Colorado

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

We conducted our audit 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 Partnership’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 audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Field Services, LLC and subsidiaries at December 31, 2005, and the results of their operations and their cash flows for the year 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 10, 2006

(March 31, 2006 as to the financial statement schedule listed in the Index at Item 15)

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

(millions)

	Year Ended December 31,
	2005
Operating revenues:
Sales of natural gas and petroleum products	$	10,011
Sales of natural gas and petroleum products to affiliates		2,785
Transportation, storage and processing		253
Trading and marketing losses		(15	)
Total operating revenues		13,034
Operating costs and expenses:
Purchases of natural gas and petroleum products		10,133
Purchases of natural gas and petroleum products from affiliates		830
Operating and maintenance		447
Depreciation and amortization		287
General and administrative		195
Gain on sale of assets		(2	)
Total operating costs and expenses		11,890
Operating income		1,144
Gain on sale of general partner interest in TEPPCO		1,137
Equity in earnings of unconsolidated affiliates		22
Minority interest income		1
Interest income		26
Interest expense		(154	)
Income from continuing operations before income taxes		2,176
Income tax expense		(9	)
Income from continuing operations		2,167
Income from discontinued operations, net of income taxes		3
Net income		2,170
Other comprehensive loss:
Foreign currency translation adjustment		(8	)
Canadian business distributed to Duke Energy		(70	)
Reclassification of cash flow hedges into earnings		1
Total other comprehensive loss		(77	)
Total comprehensive income	$	2,093

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEET

(millions)

	As of December 31,
	2005
ASSETS
Current assets:
Cash and cash equivalents	$	59
Short-term investments		627
Accounts receivable:
Customers, net of allowance for doubtful accounts of $4 million		1,237
Affiliates		340
Other		59
Inventories		110
Unrealized gains on mark-to-market and hedging transactions		252
Other		22
Total current assets		2,706
Property, plant and equipment, net		3,836
Restricted investments		364
Investments in unconsolidated affiliates		169
Intangible assets:
Commodity sales and purchases contracts, net		66
Goodwill		421
Total intangible assets		487
Unrealized gains on mark-to-market and hedging transactions		60
Deferred income taxes		3
Other non-current assets		86
Total assets	$	7,711
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,035
Affiliates		42
Other		42
Current maturities of long-term debt		300
Unrealized losses on mark-to-market and hedging transactions		244
Distributions payable to members		185
Accrued interest payable		45
Accrued taxes		46
Other		129
Total current liabilities		3,068
Long-term debt		1,760
Unrealized losses on mark-to-market and hedging transactions		54
Other long-term liabilities		224
Minority interests		95
Commitments and contingent liabilities
Members’ equity:
Members’ interest		2,107
Retained earnings		411
Accumulated other comprehensive loss		(8	)
Total members’ equity		2,510
Total liabilities and members’ equity	$	7,711

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(millions)

	Year Ended December 31,
	2005
Cash flows from operating activities:
Net income	$	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	)
Depreciation and amortization		287
Distributions received in excess of earnings from unconsolidated affiliates		15
Deferred income tax benefit		(2	)
Other, net		(1	)
Change in operating assets and liabilities (net of effects of acquisitions) Which (used) provided cash:
Accounts receivable		(432	)
Inventories		(37	)
Net unrealized losses (gains) on mark-to-market and hedging transactions		9
Accounts payable		910
Accrued interest payable		(14	)
Other		(12	)
Net cash provided by continuing operations		1,753
Net cash provided by discontinued operations		11
Net cash provided by operating activities		1,764
Cash flows from investing activities:
Capital and acquisition expenditures		(212	)
Purchase of investment in unconsolidated affiliate		(13	)
Investment expenditures, net of cash acquired		(11	)
Purchases of available-for-sale securities		(17,986	)
Proceeds from sales of available-for-sale securities		17,260
Proceeds from sales of discontinued operations		30
Proceeds from sales of assets and general partner interest in TEPPCO		1,123
Other		9
Net cash provided by continuing operations		200
Net cash used in discontinued operations		(13	)
Net cash provided by investing activities		187
Cash flows from financing activities:
Payment of dividends and distributions to members		(2,313	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		206
Contribution received from ConocoPhillips		398
Payment of debt		(607	)
Proceeds from issuing debt		408
Loans made to Duke Capital LLC and ConocoPhillips		(1,100	)
Repayment of loans by Duke Capital LLC and ConocoPhillips		1,100
Cash received from minority interests		3
Other		(2	)
Net cash used in continuing operations		(1,907	)
Net cash used in discontinued operations		(44	)
Net cash used in financing activities		(1,951	)
Net change in cash and cash equivalents		—
Cash and cash equivalents, beginning of year		59
Cash and cash equivalents, end of year	$	59
Supplementary cash flow information:
Cash paid for interest (net of amounts capitalized)	$	163

See Notes to Consolidated Financial Statements.

4

5

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

(millions)

	Year Ended December 31, 2005
	Members’ Interest		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2005	$	1,709	$	909		$	69		$	2,687
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

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, 2005

1. General and Summary of Significant Accounting Policies

Basis of Presentation—Duke Energy Field Services, LLC (with its consolidated subsidiaries, “us”, “we”, “our”, or the “Company”) operates in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, transportation and storage and natural gas liquid, or NGL, fractionation, transportation, compression, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. Our limited liability company agreement (“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 recently formed DCP Midstream Partners, LP, a master limited partnership (“DCP Midstream Partners”) of which our subsidiary, DCP Midstream GP LP, acts as general partner. In September 2005, DCP Midstream Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission (“SEC”) to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. As a result of DCP Midstream Partners’ initial public offering, we own approximately 40% of the limited partnership interests in DCP Midstream Partners and a 2% general partnership interest. As the general partner of DCP Midstream Partners, we have responsibility for its operations. DCP Midstream Partners is accounted for as a consolidated subsidiary.

In July 2005, Duke Energy Corporation (“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% (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 are designated for the acquisition or improvement of property, plant and equipment. At December 31, 2005, the remaining balance related to this contribution of approximately $264 million was included in the consolidated balance sheet as restricted investments.

We are governed by a five member Board of Directors, consisting of two voting members from each parent and a single non-voting member who is our Chief Executive Officer and President. 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 Duke Energy and ConocoPhillips Board member. In the event the Board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Duke Energy and ConocoPhillips.

On January 31, 2005, we filed a Form 15 with the SEC to suspend our reporting obligations under the Securities Exchange Act of 1934. We are eligible to suspend our reporting obligations under the 1934 Act because we have fewer than 300 holders of record of any class of our securities. DCP Midstream Partners is a public registrant and reports under the Securities Exchange Act of 1934.

Consolidation—The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, our general partner interest in a limited partnership where the limited partners do not have substantive kick-out or participating rights, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets, after eliminating intercompany transactions and balances. Investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method (see Note 10).

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.

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.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 (“SFAS”) No. 115 (“SFAS 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 sheet as accumulated other comprehensive income (loss) (“AOCI”). No gains or losses were deferred in AOCI at December 31, 2005.

As of December 31, 2005 we had short-term investments of $627 million which were available for general corporate purposes.

In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash is invested in financial instruments as described above, however, under the terms of the amended and restated LLC Agreement, proceeds from this contribution are designated for the acquisition or improvement of property, plant and equipment. As this cash is to be used to acquire non-current assets, it has been classified as a long-term asset in the consolidated balance sheet. At December 31, 2005, we had restricted investments related to this contribution of $264 million. At December 31, 2005, we also had restricted investments of $100 million consisting of collateral for DCP Midstream Partners’ term loan (see Note 12).

Inventories—Inventories consist primarily of natural gas and NGLs held in storage for transmission and processing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method (see Note 6).

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 (“SFAS 133”),“Accounting for Derivative Instruments and Hedging Activities,” as amended, is recorded on a gross basis in the consolidated balance sheet at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging transactions. Derivative assets and liabilities remain classified in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions at fair value until the contractual delivery period occurs.

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 statement of operations are as follows:

Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market(a)	Net basis in trading and marketing losses and gains
Non-Trading Derivatives:
Cash Flow Hedge	Hedge method(b)	Gross basis in the same statement of operations category as the related hedged item
Fair Value Hedge	Hedge method(b)	Gross basis in the same statement of operations category as the related hedged item
Normal Purchase or Normal Sale	Accrual method(c)	Gross basis upon settlement in the corresponding statement of operations category based on purchase or sale
Non-Trading Derivative Activity	Mark-to-market(a)	Net basis in trading and marketing losses and gains

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

(b) Hedge method—An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the consolidated balance sheet and there is no recognition in the consolidated statement of operations for the effective portion until the service is provided or the associated delivery period occurs.

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

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.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheet as AOCI and the ineffective portion is recorded in the consolidated statement of operations. During the period in which the hedged transaction occurs, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statement of operations in the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will 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 sheet 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 occurs, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings. We exclude the time value of the options when assessing hedge effectiveness.

For derivatives designated as fair value hedges, the Company recognizes 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 statement of operations.

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

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

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 (see Note 9).

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of 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 a comparison of 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. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount (see Note 9).

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 (see Note 7). 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 Long-Lived Assets, Assets Held for Sale and Discontinued Operations—We evaluate whether the carrying value of long-lived assets, excluding goodwill, have 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 in the business climate;

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• 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 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 re-assess the cash flows related to the long-lived assets.

We use the criteria in SFAS No. 144 (“SFAS 144”),“Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 sheet.

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 (loss) from discontinued operations in the consolidated statement of operations. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statement of operations.

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 an 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.

Revenue Recognition—Our primary types of sales and service activities reported as operating revenue include:

• Sales of natural gas and petroleum products;

• Natural gas gathering, processing, transportation and storage, and trading and marketing from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Services”); and

• NGL fractionation, transportation, and trading and marketing from which we generate revenues primarily by providing services such as transportation, market center fractionation and the trading and marketing of NGLs (the “NGL Services”).

Revenues associated with sales of natural gas and petroleum products are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues for Natural Gas Services and NGL Services are recognized when the service is provided. We defer revenue recognition on all sales and service activities until the price is fixed or determinable and collectability is reasonably assured.

For gathering services, we receive fees from the producers to transport the natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, we are paid for our services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, we keep a portion of the NGLs produced, but return the equivalent energy content of the gas

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back to the producer. We also receive fees for further fractionation of the NGLs produced, and for transportation and for storage of NGLs and residue gas. Under a wellhead purchase contract, we purchase raw natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices.

We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statement of operations as trading and marketing losses and gains, in accordance with Emerging Issues Task Force (“EITF”) Issue No. 02-3,“Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” These activities include mark-to-market gains and losses on energy trading contracts and the financial or physical settlement of energy trading contracts.

We generally report revenues gross in the consolidated statement of operations, in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based agreements, we act as the principal in these transactions, take title to the product, and incur the risks and rewards of ownership.

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. 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, 2005.

Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in 2005. Sales to ConocoPhillips, including its affiliate, ChevronPhillips Chemical Company LLC (“CP Chem”), totaled approximately $2,513 million during 2005.

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 sheet as an offset to long-term debt. These expenses are recorded on the consolidated balance sheet as other non-current assets.

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, 2005 included in the consolidated balance sheet totaled $6 million recorded as other current liabilities and $7 million recorded as other long-term liabilities.

Gas and NGL Imbalance Accounting—Quantities of natural gas or NGL over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using then 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 sheet as accounts receivable—other as of December 31, 2005 were imbalances totaling $59 million. Included in the consolidated balance sheet as accounts payable—other, as of December 31, 2005 were imbalances totaling $42 million.

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 statement 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, 2005.

Income Taxes—We are structured as a limited liability company which is a pass-through entity for U.S. income tax purposes. We own corporations who file their own respective federal, foreign and state corporate income tax returns. The income tax expense related to these corporations is included in our income tax expense, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries which 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 (see Note 11).

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Distributions—Under the terms of our LLC Agreement, we are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement, as amended, 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 Duke Energy and ConocoPhillips. Prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the year ended December 31, 2005, we paid distributions of $389 million 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 considers the payment of a quarterly dividend to Duke Energy and ConocoPhillips. The Board of Directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. During the year ended December 31, 2005, we paid total dividends of $1,925 million, 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. Our LLC Agreement restricts payment of dividends except with the approval of both members.

DCP Midstream Partners intends to distribute to the holders of its common units and subordinated units on a quarterly basis at least DCP Midstream Partners’ minimum quarterly distribution of $0.35 per unit, or $1.40 per year, to the extent DCP Midstream 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. However, there is no guarantee that DCP Midstream Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Midstream Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit agreement. Our 40% limited partner interest in DCP Midstream Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Midstream 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.

Stock-Based Compensation—Under its 1998 Long-Term Incentive Plan (“1998 Plan”), Duke Energy granted certain of our key employees stock options, restricted stock, phantom stock awards and stock-based performance awards to be settled in shares of Duke Energy’s common stock. Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25 (“APB 25”),“Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44 (“FIN 44”),“Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense is 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 statement of operations. Compensation expense for restricted stock grants and phantom stock awards is 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 is recorded over the required vesting period, and is adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

Upon execution of the 50-50 Transaction in July 2005, certain employees of Duke Energy Field Services 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 options were required to be re-measured as of July 2005 under EITF Issue No. 96-18 (“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 (“SFAS 123”),“Accounting for Stock-Based Compensation.” 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 the stock options at each reporting date.

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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 six month period ended June 30, 2005 (millions):

Net income, as reported	$	1,582
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	$	1,582

Accounting for Sales of Units by a Subsidiary—In December 2005, we formed DCP Midstream 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 Midstream 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 (“SAB”) No. 51 (“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 the gain on sale of common units in DCP Midstream Partners in the amount of approximately $149 million as other long-term liabilities in the consolidated balance sheet. We will recognize this gain in earnings upon conversion of our subordinated units in DCP Midstream Partners to common units.

New Accounting Standards—SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Corrections.” In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20,“Accounting Changes” and FASB Statement 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 on the new accounting principle, unless it is impracticable to do so. SFAS 154 also provides that (1) a change in method of depreciating or amortizing 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) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 depends on the nature and extent of any changes in accounting principles after the effective date, but we do not currently expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.

Emerging Issues Task Force Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”In September 2005, the EITF reached consensus on EITF 04-13. In general, an entity would be required under the consensus 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 (“APB 29”) when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. If the consensus is ratified by the FASB, an affected entity should apply the consensus to new arrangements that it enters into in reporting periods beginning after March 15, 2006. We do not currently expect EITF 04-13 to have a material impact on our consolidated results of operations, cash flows or financial position.

EITF Issue No. 04-5 (“EITF 04-5”), “Determining Whether a General Partner, or the General Partners As a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” In June 2005, the FASB ratified the EITF’s consensus on Issue 04-5 regarding control of a limited partnership. There is a presumption that the general partner in a limited partnership or similar entity has control unless the limited partners have substantive kick-out rights or participating rights. For general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified, EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. DCP Midstream Partners was formed in the third quarter of 2005 and is accounted for as a consolidated subsidiary in accordance with EITF 04-5.

Financial Accounting Standards Board Interpretation No. 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations.” In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS 143. A conditional asset retirement obligation is 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. Therefore, an entity is

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required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The adoption of FIN 47 did not have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment.”In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supersedes APB 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first annual period after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. We do not currently expect SFAS 123R to have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.”In December 2004, the FASB issued SFAS 153, which amends APB 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS 153 did not have a material impact on our consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13 (“EITF 03-13”), “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The adoption of EITF 03-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

2. Impairment of Goodwill

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 included 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, 2005. 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. There were no impairments of goodwill for the year ended December 31, 2005.

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3. Acquisitions and Dispositions

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, the purchase price less the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

Acquisition of Various Gathering, Transmission and Processing Assets—In March 2005, we purchased pipeline, compressor station and metering station assets in East Texas for a total purchase price of approximately $4 million in cash, the estimated fair value of the assets. As the acquired assets were not considered businesses under the guidance in EITF Issue No. 98-3,“Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business”(“EITF 98-3”), no goodwill was recognized in connection with this transaction.

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

Dispositions

Disposition of Various Gathering, Transmission and Processing Assets—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 March 2005, we sold certain vehicles and personal property in Colorado for a sales price of approximately $3 million and recognized a $2 million gain.

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.

Assets Held for Sale and Discontinued Operations

Assets Held for Sale—In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified 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. These transactions are expected to close in the first half of 2006.

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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 classified as discontinued operations for the period 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

Disposition of Various Gathering, Transmission and Processing Assets—In December 2004, based upon management’s assessment of the probable disposition of certain processing plant assets in Wyoming, we classified certain assets as held for sale. The results of operations and cash flows related to these assets have been classified as discontinued operations for the period presented. In February 2005, we exchanged these assets for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.

In September 2004, based upon management’s assessment of the probable disposition of certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming, we classified these assets as held for sale. The results of operations and cash flows related to these assets have been classified as discontinued operations for the period presented. In February 2005, we sold these assets for approximately $28 million.

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 classified as discontinued operations for the period presented.

The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005 (millions):

Operating revenues	$	35
Pre-tax operating income	$	4
Income tax expense		(1	)
Operating income, net of tax		3
Income from discontinued operations	$	3

4. Agreements and Transactions with 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.

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DUKE ENERGY FIELD SERVICES, LLC

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The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging transactions with affiliates as of December 31, 2005 (millions):

Unrealized gains on mark-to-market and hedging transactions—current	$	27
Unrealized gains on mark-to-market and hedging transactions—non-current	$	19
Unrealized losses on mark-to-market and hedging transactions—current	$	(24	)
Unrealized losses on mark-to-market and hedging transactions—non-current	$	(20	)

The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the year ended December 31, 2005 (millions):

Duke Energy:
Sales of natural gas and petroleum products to affiliates	$	109
Transportation, storage and processing	$	2
Purchases of natural gas and petroleum products from affiliates	$	130
Operating and general and administrative expenses	$	44
Interest income	$	8
Operating lease expense	$	4
ConocoPhillips:
Sales of natural gas and petroleum products to affiliates	$	2,513
Transportation, storage and processing	$	11
Purchases of natural gas and petroleum products from affiliates	$	556
Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	163
Transportation, storage and processing	$	20
Purchases of natural gas and petroleum products from affiliates	$	144

Duke Energy

Services Agreements—Under a services agreement that is negotiated and renewed on an annual basis, Duke Energy and certain of its subsidiaries provide us with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, media relations, printing, records management and legal functions. These services are priced on the basis of a monthly charge. Additionally, we may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

Included in accounts receivable—affiliates in the consolidated balance sheet are insurance recovery receivables of $39 million at December 31, 2005 from an insurance provider that is a subsidiary of Duke Energy. There were no prepaid insurance premiums as of December 31, 2005. During 2005 we recorded business interruption insurance recoveries related to Hurricanes Ivan and Katrina of $3 million, included in the consolidated statement of operations as sales of natural gas and petroleum products.

License Agreement—Duke Energy has licensed to us a non-exclusive right to use the phrase “Duke Energy” and its logo and certain other trademarks in identifying our businesses. This right may be terminated by Duke Energy at its sole option with one year prior written notice to us or upon the sale of Duke Energy’s interest in us.

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 its subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Duke 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 (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement (the “ConocoPhillips NGL Agreement”) between us and ConocoPhillips, a wholly-owned subsidiary of ConocoPhillips 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 ConocoPhillips NGL Agreement

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DUKE ENERGY FIELD SERVICES, LLC

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also grants ConocoPhillips, and subsequently 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.

Transactions with other unconsolidated affiliates

We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to unconsolidated affiliates. We anticipate continuing to purchase and sell 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, 2005.

5. Marketable Securities

Short-term and restricted investments—At December 31, 2005 we had $627 million of short-term investments and $364 million of restricted investments consisting primarily of highly liquid tax-exempt debt securities. 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.

6. Inventories

A summary of inventories as of December 31, 2005 by category follows (millions):

Natural gas held for resale	$	43
NGLs		67
Total inventories	$	110

7. Property, Plant and Equipment

A summary of property, plant and equipment as of December 31, 2005 by classification follows (millions):

	Depreciable Life
Gathering	15 - 30 years	$	2,503
Processing	25 - 30 years		1,840
Transmission	25 - 30 years		1,223
Underground storage	20 - 50 years		103
General plant	3 - 5 years		138
Construction work in progress			108
			5,915
Accumulated depreciation			(2,079	)
Property, plant and equipment, net		$	3,836

Depreciation expense for the year ended December 31, 2005 was $278 million. Interest capitalized on construction projects in 2005 was approximately $2 million. At December 31, 2005 we had non-cancelable purchase obligations of approximately $16 million for capital projects expected to be completed in 2006. In addition, property, plant and equipment includes $13 million of non-cash additions for the year ended December 31, 2005.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

8. 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, which do not trigger a 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 only be recorded if and when a future retirement obligation with a determinable life is identified.

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 sheet, for the year ended December 31, 2005 (millions):

Balance as of January 1	$	57
Accretion expense		3
Liabilities incurred		1
Distribution of Canadian business to Duke Energy		(10	)
Other		(1	)
Balance as of December 31	$	50

9. Goodwill and Other Intangibles

The changes in the carrying amount of goodwill are as follows for the year ended December 31, 2005 (millions):

Goodwill as of January 1	$	452
Purchase price adjustments		(11	)
Foreign currency translation adjustments		(2	)
Distribution of Canadian business to Duke Energy		(18	)
Goodwill as of December 31	$	421

During 2005, the Company 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 taxes 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, 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 year ended December 31, 2005 (millions):

Commodity sales and purchases contracts	$	130
Accumulated amortization		(64	)
Commodity sales and purchases contracts, net	$	66

During the year ended December 31, 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these contracts range from 1 to 21 years with a weighted average remaining period of approximately 8 years.

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DUKE ENERGY FIELD SERVICES, LLC

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

2006	$	8
2007		8
2008		8
2009		8
2010		8
Thereafter		26
Total	$	66

10. Investments in Unconsolidated Affiliates

We have investments in the following unconsolidated affiliates accounted for using the equity method as of December 31, 2005 (millions):

	Ownership
Discovery Producer Services LLC	40.00	%	$	102
Sycamore Gas System General Partnership	48.45	%		13
Mont Belvieu I	20.00	%		12
Tri-States NGL Pipeline, LLC	16.67	%		9
Main Pass Oil Gathering Company	33.33	%		13
Fox Plant, LLC	50.00	%		7
Black Lake Pipe Line Company	50.00	%		6
Other unconsolidated affiliates	Various			7
Total investments in unconsolidated affiliates			$	169

Discovery Producer Services LLC—Discovery Producer Services LLC (“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 $53 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

Sycamore Gas System General Partnership—Sycamore Gas System General Partnership (“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 $10 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Mont Belvieu I—Mont Belvieu I operates a 200 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 $12 million at December 31, 2005 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 (“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, 2005 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.”

Main Pass Oil Gathering Company—Main Pass Oil Gathering Company is 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.

Fox Plant, LLC—Fox Plant, LLC is a limited liability company formed for the purpose of constructing, owning and operating a gathering facility and gas processing plant in Carter County, Oklahoma.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Black Lake Pipe Line Company—Black Lake Pipe Line Company (“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 $8 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

TEPPCO Partners, L.P.—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. During 2005, total cash distributions to the general partner of TEPPCO were approximately $17 million.

Equity in earnings of unconsolidated affiliates amounted to the following for the year ended December 31, 2005 (millions):

TEPPCO Partners, L.P.	$	8
Discovery Producer Services LLC		11
Sycamore Gas System General Partnership		(1	)
Mont Belvieu I		(1	)
Tri-States NGL Pipeline, LLC		1
Main Pass Oil Gathering Company		3
Other unconsolidated affiliates		1
Total equity in earnings of unconsolidated affiliates	$	22

Distributions received in excess of earnings were $15 million in 2005.

The following summarizes combined financial information of unconsolidated affiliates for the year ended and as of December 31, 2005 (millions):

Income statement:
Operating revenues	$	328
Operating expenses	$	312
Net income	$	18
Balance sheet:
Current assets	$	133
Non-current assets		740
Current liabilities		81
Non-current liabilities		6
Net assets	$	786

11. Income Taxes

We are a limited liability company which is a pass-through entity for U.S. income tax purposes. We own corporations who file their own respective federal and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income tax as presented in the consolidated statement of operations is summarized as follows for the year ended December 31, 2005 (millions):

Current:
Federal	$	9
State		2
Total current		11
Deferred:
State		(2	)
Total deferred		(2	)
Total income tax expense	$	9

Our temporary differences primarily relate to depreciation on property, plant and equipment. Cash paid for income taxes was $13 million for the year ended December 31, 2005.

12. Financing

Debt Securities —In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015 (“5.375% Notes”), for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We will 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 our Term Loan Facility (see 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 Term Loan Facility (see below).

Credit Facilities with Financial Institutions—On December 7, 2005, DCP Midstream Partners entered into a 5-year credit agreement (the “DCP Credit Agreement”) that consists of a $250 million revolving credit facility and a $100 million term loan facility. The DCP Credit Agreement matures on December 7, 2010. At December 31, 2005, there was $110 million 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. There were no letters of credit outstanding on the DCP Credit Agreement as of December 31, 2005. The DCP Credit Agreement requires DCP Midstream Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Midstream Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP 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 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, 2005, 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.

In August 2005, we entered into a credit agreement (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 April 29, 2005, we entered into a credit facility (the “Facility”). The Facility replaced the One-Year Facility that was scheduled to mature on May 10, 2005 (see below). The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. On December 6, 2005, we amended the Facility to extend the maturity for a period of one additional year to April 29, 2011, amend the definition of consolidated capitalization to include minority interest and amend the pricing. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

capitalization ratio of less than or equal to 60%; 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 Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments). 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, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.

On March 26, 2004, we entered into a credit facility (the “One-Year Facility”). The One-Year Facility replaced the credit facility that matured on March 26, 2004. The One-Year Facility was a $250 million revolving credit facility used to support our commercial paper program and for working capital and other general corporate purposes. In December 2004, the One-Year Facility was amended to extend the maturity date to May 10, 2005. On April 29, 2005, the One-Year Facility was terminated.

In October 2001, we entered into an interest rate swap to convert the fixed interest rate of $250 million of debt securities that 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 August 2005, the date at which this swap and the underlying debt matured. In August 2003, we entered into two interest rate swaps to convert the fixed interest rate of $100 million of debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges bear a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030.

Long-term debt at December 31, 2005 was as follows (millions):

	Principal/         Discount			Due Date	Interest         Rate
Debt securities	$	300		November 15, 2006	5.750	%
		800		August 16, 2010	7.875	%
		250		February 1, 2011	6.875	%
		200		October 15, 2015	5.375	%
		300		August 16, 2030	8.125	%
DCP credit facility		210		December 7, 2010	Varies
Interest rate swap		7
Unamortized discount		(7	)
Current portion of long-term debt		(300	)
Long-term debt	$	1,760

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. DCP Midstream Partners has $100 million held in restricted investments as collateral for the term loan portion of the debt held under its credit agreement. Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2005 (millions):

2006	$	300
2007		—
2008		—
2009		—
2010		1,010
Thereafter		757
		2,067
Short-term debt		(300	)
Unamortized discount		(7	)
Long-term debt	$	1,760

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Commodity price risk—Our principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, 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 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 are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with debt issuances. 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. Our corporate credit policy prescribes the use of 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, the Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allow the Company to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment in a form satisfactory to the Company.

As of December 31, 2005, we held cash or letters of credit of $99 million to secure future performance of financial or physical contracts, and had deposited with counterparties $15 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.

Hedging strategies—Historically, we have used 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 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 Midstream Partners’ operations. Some of the assets operated by DCP Midstream 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 Midstream 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 Midstream Partners, we do not currently anticipate using cash flow hedges in 2006 because management believes cash flows will be sufficient to fund our business.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Commodity cash flow hedges—During September 2005, we executed a series of derivative financial instruments effective January 1, 2006, which have been designated as cash flow hedges of the price risk through 2010, associated with forecasted sales of natural gas, NGLs and condensate related to assets of DCP Midstream 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. Historically we have used natural gas, crude oil and NGL swaps to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the year ended December 31, 2005, amounts recognized in the consolidated statement of operations for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to any forecasted transactions that are not probable of occurring. At December 31, 2005, amounts deferred in AOCI related to commodity cash flow hedges were not significant. As of December 31, 2005, $2 million of deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur; 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 year ended December 31, 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—Prior to issuing fixed rate debt in August 2000, the Company 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 deferred balance was $8 million at December 31, 2005. 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 that 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, 2005, the fair value of the interest rate swaps was an $8 million asset, which is included in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions 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.

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DUKE ENERGY FIELD SERVICES, LLC

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14. Estimated Fair Value of Financial Instruments

We have determined the following fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The carrying amount and estimated fair value of our financial instruments are as follows at December 31, 2005 (millions):

	Carrying Amount			Estimated Fair Value
Short-term investments	$	627		$	627
Restricted investments		364			364
Accounts receivable		1,636			1,636
Accounts payable		(2,119	)		(2,119	)
Unrealized gains on mark-to-market and hedging transactions		14			14
Current maturities of long-term debt		(300	)		(302	)
Long-term debt		(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.

The estimated fair value of the natural gas, NGLs and crude oil derivative contracts is determined by multiplying the difference between the quoted termination prices for natural gas, NGLs and crude oil and the derivative contract prices by the quantities under contract. The estimated fair value of options is determined by the Black-Scholes option valuation model.

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

15. 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. However, these class actions can be costly and time consuming to defend. Management believes that, based on currently known information, these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

General Insurance—We carry insurance coverage, with an affiliate of Duke Energy, that management believes is consistent with companies engaged in similar commercial operations with similar type properties. 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. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of our general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

During the third quarter 2004, certain assets, located in the Gulf Coast, were damaged as a result of Hurricane Ivan. Management believes that the resulting losses will be covered by insurance, subject to applicable deductibles for property and business interruption. Included in accounts receivable—affiliate on the consolidated balance sheet are insurance recovery receivables related to Hurricane Ivan of $29 million at December 31, 2005 from an insurance provider that is a subsidiary of Duke Energy.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. Substantially all of our facilities have resumed operations, but some facilities are not yet operating at the same levels of capacity utilization as they operated before the hurricanes. Several of our assets sustained property damage including some of our operating equipment on a platform in the Gulf of Mexico. We expect that a portion of the resulting lost revenues and property damage will be covered by our insurance, subject to applicable deductibles. We expect that the financial impact of recent hurricanes may increase market rates for insurance coverage in the future, however, we do not expect these increases to have a material adverse effect on our consolidated results of operations, financial position or cash flows. Included in accounts receivable—affiliate on the consolidated balance sheet are insurance recovery receivables related to Hurricane Katrina of $5 million at December 31, 2005 from an insurance provider that is a subsidiary of Duke Energy. Insurance recovery receivables related to Hurricane Rita are insignificant.

During the year ended December 31, 2005, we recorded business interruption insurance recoveries related to these hurricanes of $3 million in the consolidated statement of operations 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.

Other Commitments and Contingencies—We utilize assets under operating leases in several areas of operations. Rental expense, including leases with no continuing commitment, amounted to $36 million in 2005. 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, 2005 (millions):

2006	$	22
2007		19
2008		17
2009		13
2010		13
Thereafter		51
Total gross payments		135
Sublease receipts		(4	)
Total net payments	$	131

26

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16. Stock-Based Compensation

Under Duke Energy’s 1998 Plan, stock options for Duke Energy’s common stock were granted to certain of our key employees. 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 five years with a maximum option term of 10 years.

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

Stock Option Activity
	Options (thousands)		Weighted-Average Exercise Price
Outstanding at January 1, 2005	2,956		$	29
Exercised	(302	)		20
Forfeited	(61	)		31
Outstanding at December 31, 2005	2,593		$	29

Stock Options at December 31, 2005
	Outstanding			Exercisable
Range of Exercise Prices	Number (thousands)	Weighted- Average Remaining Life (years)	Weighted- Average Exercise Price	Number (thousands)	Weighted- Average Exercise Price
$11 to $16	587	7.1	$14	235	$14
$17 to $22	28	6.1	18	28	18
$23 to $28	747	3.4	26	747	26
$29 to $34	97	3.5	30	97	30
$35 to $40	647	6.0	38	641	38
> $40	487	5.0	43	487	43
Total	2,593	5.2	$29	2,235	$32

There were no options granted in 2005.

Upon execution of the 50-50 Transaction in July 2005, the employees referred to above incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased using the intrinsic value method under APB 25 and FIN 44 to account for all outstanding unvested options. 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 occurs. Compensation expense for outstanding unvested options was not significant for the year ended December 31, 2005.

Duke Energy granted stock-based performance awards of Duke Energy common stock to certain of our key employees under the 1998 Plan. Stock-based performance awards under the 1998 Plan vest over periods ranging from three to seven years. Vesting can occur in three years, at the earliest, if certain performance objectives are met. Duke Energy awarded 160,910 stock-based performance awards (fair value of approximately $4 million at grant dates) in 2005. Compensation expense for stock-based performance awards is recognized over the required vesting period and amounted to approximately $3 million in 2005.

Duke Energy granted phantom shares of Duke Energy common stock to certain of our employees under the 1998 Plan. Phantom stock awards under the 1998 Plan vest over periods ranging from one to five years. Duke Energy awarded 128,850 phantom awards (fair value of approximately $3 million at grant dates) in 2005. Compensation expense for phantom awards is recognized over the required vesting period and amounted to approximately $2 million in 2005.

Duke Energy granted restricted shares of Duke Energy common stock to certain of our employees under the 1998 Plan. Restricted shares under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 3,000 restricted shares (fair value of less than $1 million at grant date) in 2005. Compensation expense for restricted shares is recognized over the required vesting period and amounted to less than $1 million in 2005.

In February 2006, we adopted a long-term incentive plan (see Note 19). On a prospective basis, we will not participate in Duke Energy’s 1998 Plan.

27

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. 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 in which we contribute 4% of each eligible employee’s qualified earnings. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2005 we expensed plan contributions of $15 million.

We offer certain eligible executives the opportunity to participate in the Duke Energy Field Services’ LP 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. Additionally, certain of our executives participate in restricted stock and other compensatory plans. Total expense for all of our executive compensatory plans was $5 million in 2005.

18. 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 $22 million of construction obligations. This guaranty will be reduced by construction payments and 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 December 31, 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

19. Subsequent Events

On January 25, 2006, DCP Midstream Partners announced the declaration of a cash distribution of $0.095 per unit, payable on February 13, 2006 to unitholders of record on February 3, 2006. That distribution represents the pro rata portion of their minimum quarterly cash distribution of $0.35 per unit for the period December 7, 2005 through December 31, 2005.

In February 2006, we adopted a long-term incentive plan (the “2006 LTI Plan”). Under the 2006 LTI Plan, the Board of Directors may award phantom units, including dividend/distribution rights, equal to the weighted average fair value of a common share of ConocoPhillips, Duke Energy and DCP Midstream Partners. The phantom units may be settled in cash or equity securities at the discretion of the Board of Directors. The weighted percentage for each such unit is 45%, 45% and 10%, respectively. The Board of Directors has the discretion to determine the vesting period for phantom units granted under the 2006 LTI Plan, however these units will generally vest over three to eight years, contingent upon the grantee continuing to be an employee of the Company.

28

DUKE ENERGY FIELD SERVICES, LLC

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Increases
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts(b)			Deductions(c)			Balance at End of Period
	($ in millions)
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 liabilities which are included in other current liabilities.

(b) Consists of other contingency reserves reclassified to litigation reserve accounts.

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

29

EXHIBIT INDEX

Exhibits filed with the original Form 10-K on March 3, 2006 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, 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 May 8, 2005, by and among the registrant, Cinergy Corp., Deer Holding Corporation, Deer Acquisition Corp., and Cougar Acquisition Corp. (filed in Form 8-K of the registrant, May 9, 2005, File No. 1-4928, as Exhibit 2-1).
2.1.1	Amendment No. 1 to the Agreement and Plan of Merger, dated July 11, 2005, by and among the registrant, Cinergy Corp., Duke Energy Holding Corp., Deer Acquisition Corp., and Cougar Acquisition Corp. (filed with Form 10-Q of the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 2-1.1).
2.1.2	Amendment No. 2 to the Agreement and Plan of Merger, dated October 3, 2005, by and among the registrant, Cinergy Corp., Duke Energy Holding Corp., Deer Acquisition Corp., and Cougar Acquisition Corp. (filed with Form 8-K of the registrant dated October 7, 2005, File No. 1-4928, 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 the registrant for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit 10-7).
3.1	Restated Articles of Incorporation of registrant, dated June 18, 1997 (filed with Form S-8, No. 333-29563, effective June 19, 1997, as Exhibit 4(G)).
3.1.1	Articles of Amendment to Restated Articles of Incorporation of registrant, dated February 9, 1999 (filed with Form 8-K of the registrant on February 11, 1999, File No. 1-4928, as Exhibit A to Exhibit 4.1).
3.1.2	Articles of Amendment to Restated Articles of Incorporation of registrant, dated April 28, 1999 (filed with Form S-3 of the registrant, file number 333-81573, filed June 25, 1999 as Exhibit 4(B)).
3.1.3	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 2, 2001 (filed with Post-Effective Amendment No. 2 to Form S-3 of the registrant, file number 333-81573, filed December 12, 2001, as Exhibit 4(B)-1).
3.1.4	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 1, 2002 (filed with Form 10-Q of the registrant for the quarter ended March 31, 2002, File No. 1-4928, as Exhibit 3).
3.1.5	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 12, 2005 (filed with Form 10-Q of the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 3-1.5).
3.2	By-Laws of registrant, as amended and restated May 12, 2005 (filed with Form 10-Q of the registrant for the quarter ended June 30, 2005, File No. 1-4928, 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 Form 8-K dated February 11, 1999, 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 in Form 8-K of the registrant, 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 the registrant 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 the registrant 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 the registrant 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 the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-4.1).

Exhibit Number
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 the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-4.2).
10.4	Intentionally Omitted
*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.
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 the registrant 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 Barclays Bank PLC, dated as of November 17, 2005.
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 the registrant 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant, March 28, 2003, File No. 1-4928).
10.16**	Duke Energy Corporation Executive Short-Term Incentive Plan (filed as Exhibit 2 to Schedule 14A of registrant, March 28, 2003, File No. 1-4928).
10.7**	Duke Energy Corporation Executive Savings Plan, as amended and restated (filed with Form 10-K of the registrant for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-6).

Exhibit Number
10.7.1**	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 the registrant for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-6.1).
10.18**	Duke Energy Corporation Executive Cash Balance Plan (filed with Form 10-K Report 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.4).
10.19**	Duke Energy Corporation Retirement Benefit Equalization Plan (filed with Form 10-K Report of TEPPCO Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10.9).
10.20**	Form of Key Employee Severance Agreement and Release between Duke Energy Corporation and certain key executives (filed with Form 10-K of the registrant for the year ended December 31, 1999, 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 the registrant for the year ended December 31, 1999, 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 the registrant dated 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 the registrant for 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 the registrant for 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 the registrant for 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 the registrant for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.3).
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 the registrant for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.4).
10.24**	Supplemental Compensation Agreement dated June 17, 1997 between Duke Power Company and Dr. Ruth G. Shaw (filed with Form 10-K of the registrant for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-19).
10.25**	Resolution of Board of Directors, February 22, 2005, Approving Award of Phantom Stock to Nonemployee Directors (filed with Form 10-Q of the registrant for 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 the registrant for 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 as Exhibit 10-1 of Current Report on Form 8-K of the registrant, filed on February 28, 2005).

Exhibit Number
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 as Exhibit 10-2 of Current Report on Form 8-K of the registrant, filed on February 28, 2005).
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 the registrant 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 the registrant, 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 10K of the registrant for 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 the registrant for 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 the registrant, 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 the registrant, 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 the registrant, February 28, 2005, File No. 1-4928, as item 3 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 the registrant, 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 the registrant, 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 the registrant, December 22, 2005, File No. 1-4928, as item 1 of Item 1.01).
12*	Computation of Ratio of Earnings to Fixed Charges.
23.1*	Consent of Independent Registered Public Accounting Firm.
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.
31.1****	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.
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.
32.1****	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.
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.