Spectra Energy Capital 10-Q 2005 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For quarter ended June 30, 2005 Commission file number 0-23977

DUKE CAPITAL LLC

(Exact name of registrant as specified in its charter)

Delaware	51-0282142
(State or other jurisdiction of Incorporation)	(IRS Employer Identification No.)
526 South Church Street Charlotte, NC	28202-1803
(Address of principal executive offices)	(Zip Code)

704-594-6200

(Registrant’s telephone number, including area code)

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ Nox

The registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

All of the registrant’s limited liability company member interests are directly owned by Duke Energy Corporation (File No. 1-4928), which files reports and proxy materials pursuant to the Securities Exchange Act of 1934, as amended.

INDEX

DUKE CAPITAL LLC

FORM 10-Q FOR THE QUARTER ENDED June 30, 2005

Item		Page
PART I. FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004	1
	CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2005 AND DECEMBER 31, 2004	2
	CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004	4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	5
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	51
4.	CONTROLS AND PROCEDURES	52
PART II. OTHER INFORMATION
1.	LEGAL PROCEEDINGS	53
6.	EXHIBITS	53
	SIGNATURES	54

SAFE HARBOR STATEMENT UNDER THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

Duke Capital LLC’s (Duke Capital) reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Capital’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Capital’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries

• The outcomes of litigation and regulatory investigations, proceedings or inquiries

• Industrial, commercial and residential growth in Duke Capital’s service territories

• The weather and other natural phenomena

• The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates

• General economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities

• Changes in environmental and other laws and regulations to which Duke Capital and its subsidiaries are subject or other external factors over which Duke Capital has no control

• The results of financing efforts, including Duke Capital’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Capital’s credit ratings and general economic conditions

• Declines in the market prices of equity securities and resultant cash funding requirements for Duke Capital’s defined benefit pension plans

• The level of creditworthiness of counterparties to Duke Capital’s transactions

• The amount of collateral required to be posted from time to time in Duke Capital’s transactions

• Growth in opportunities for Duke Capital’s business units, including the timing and success of efforts to develop real estate, domestic and international power, pipeline, gathering, processing and other infrastructure projects

• Competition and regulatory limitations affecting the success of Duke Capital’s divestiture plans, including the prices at which Duke Capital is able to sell its assets

• The performance of electric generation, pipeline and gas processing facilities

• The extent of success in connecting natural gas supplies to gathering and processing systems and in connecting and expanding gas and electric markets

• The effect of accounting pronouncements issued periodically by accounting standard-setting bodies

• Conditions of the capital markets and equity markets during the periods covered by the forward-looking statements, and

• The ability to successfully complete merger, acquisition or divestiture plans (including Duke Energy Corporation’s merger with Cinergy Corp.); regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Capital has described. Duke Capital undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

DUKE CAPITAL LLC

Consolidated Statements of Operations

(Unaudited)

(In millions)

	Three Months Ended   June 30,						Six Months Ended June 30,
	2005			2004			2005		2004
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	3,584		$	3,195		$	6,824	$	6,265
Regulated natural gas and natural gas liquids		730			656			1,881		1,663
Total operating revenues		4,314			3,851			8,705		7,928
Operating Expenses
Natural gas and petroleum products purchased		2,717			2,310			5,637		4,997
Operation, maintenance and other		551			491			1,020		959
Fuel used in electric generation and purchased power		188			260			340		502
Depreciation and amortization		247			242			498		496
Property and other taxes		72			49			156		131
Impairment and other charges		2			3			123		3
Total operating expenses		3,777			3,355			7,774		7,088
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		12			62			54		121
(Losses) Gains on Sales of Other Assets, net		—			(13	)		32		(365	)
Operating Income		549			545			1,017		596
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		39			41			80		76
Gains on sales of equity investments		6			—			1,245		—
Other income and expenses, net		44			51			69		62
Total other income and expenses		89			92			1,394		138
Interest Expense		223			262			446		535
Minority Interest Expense		77			43			493		81
Earnings From Continuing Operations Before Income Taxes		338			332			1,472		118
Income Tax Expense from Continuing Operations		209			80			694		17
Income From Continuing Operations		129			252			778		101
Discontinued Operations
Net operating (loss) income, net of tax		(1	)		(5	)		1		3
Net gain on dispositions, net of tax		—			30			—		269
(Loss) Income From Discontinued Operations		(1	)		25			1		272
Net Income	$	128		$	277		$	779	$	373

See Notes to Consolidated Financial Statements

1

PART I

DUKE CAPITAL LLC

Consolidated Balance Sheets

(Unaudited)

(In millions)

	June 30,		December 31,
	2005		2004
ASSETS
Current Assets
Cash and cash equivalents	$	980	$	503
Short-term investments		1,040		1,135
Receivables (net of allowance for doubtful accounts of $113 at June 30, 2005 and $118 at December 31, 2004)		2,295		2,645
Inventory		476		530
Assets held for sale		15		40
Unrealized gains on mark-to-market and hedging transactions		1,009		935
Other		650		604
Total current assets		6,465		6,392
Investments and Other Assets
Investments in unconsolidated affiliates		1,316		1,292
Goodwill		4,106		4,148
Notes receivable		162		232
Unrealized gains on mark-to-market and hedging transactions		1,729		1,327
Assets held for sale		63		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $15 at June 30, 2005 and $15 at December 31, 2004)		1,354		1,128
Other		972		756
Total investments and other assets		9,702		8,967
Property, Plant and Equipment
Cost		26,037		25,862
Less accumulated depreciation and amortization		5,867		5,464
Net property, plant and equipment		20,170		20,398
Regulatory Assets and Deferred Debits		1,186		1,152
Total Assets	$	37,523	$	36,909

See Notes to Consolidated Financial Statements

2

PART I

DUKE CAPITAL LLC

Consolidated Balance Sheets

(Unaudited)

(In millions)

	June 30, 2005		December 31, 2004
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Accounts payable	$	1,808	$	1,949
Notes payable and commercial paper		—		68
Taxes accrued		438		238
Interest accrued		212		213
Liabilities associated with assets held for sale		—		30
Current maturities of long-term debt		1,669		1,326
Unrealized losses on mark-to-market and hedging transactions		764		792
Other		1,353		1,450
Total current liabilities		6,244		6,066
Long-term Debt		10,565		11,286
Deferred Credits and Other Liabilities
Deferred income taxes		3,823		3,756
Unrealized losses on mark-to-market and hedging transactions		1,017		899
Liabilities associated with assets held for sale		14		14
Other		1,056		1,046
Total deferred credits and other liabilities		5,910		5,715
Commitments and Contingencies
Minority Interests		1,925		1,486
Member’s Equity
Member’s equity		11,596		11,307
Accumulated other comprehensive income		1,283		1,049
Total member’s equity		12,879		12,356
Total Liabilities and Member’s Equity	$	37,523	$	36,909

See Notes to Consolidated Financial Statements

3

PART I

DUKE CAPITAL LLC

Consolidated Statements of Cash Flows

(Unaudited)

(In millions)

	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	779		$	373
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		503			507
Gains on sales of investments in commercial and multi-family real estate		(54	)		(121	)
(Gains) losses on sales of equity investments and other assets		(1,277	)		78
Deferred income taxes		(22	)		(51	)
Minority interest		484			68
Contribution to parent and subsidiary-sponsored pension plans		(21	)		(6	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		144			146
Receivables		382			(70	)
Inventory		59			76
Other current assets		(91	)		29
Increase (decrease) in
Accounts payable		(140	)		(248	)
Taxes accrued		202			423
Other current liabilities		(126	)		(29	)
Capital expenditures for residential real estate		(209	)		(138	)
Cost of residential real estate sold		109			80
Other, assets		116			501
Other, liabilities		18			(7	)
Net cash provided by operating activities		856			1,611
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures		(473	)		(571	)
Purchases of available-for-sale securities		(17,451	)		(14,345	)
Proceeds from sales and maturities of available-for-sale securities		17,520			13,299
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,346			689
Proceeds from the sales of commercial and multi-family real estate		77			303
Settlement of net investment hedges		(162	)		—
Other		(14	)		(37	)
Net cash provided by (used in) investing activities		843			(662	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		4			112
Payments for the redemption of:
Long-term debt		(387	)		(332	)
Preferred stock of a subsidiary		—			(76	)
Notes payable and commercial paper		(66	)		(21	)
Distributions to minority interests		(377	)		(703	)
Contributions from minority interests		330			638
Advances from parent		61			—
Capital contributions from parent		269			—
Distribution to parent		(1,050	)		—
Other		(7	)		—
Net cash used in financing activities		(1,223	)		(382	)
Changes in cash and cash equivalents associated with assets held for sale		1			40
Net increase in cash and cash equivalents		477			607
Cash and cash equivalents at beginning of period		503			378
Cash and cash equivalents at end of period	$	980		$	985
Supplemental Disclosures
Significant non-cash financing activities:
Debt retired in connection with disposition of businesses	$	—		$	838
Remarketing of senior notes	$	—		$	875
Advances from parent converted to equity	$	267		$	—

See Notes to Consolidated Financial Statements

4

PART I

DUKE CAPITAL LLC

Notes To Consolidated Financial Statements

(Unaudited)

1. Basis of Presentation

Nature of Operations and Basis of Consolidation.Duke Capital LLC (collectively with its subsidiaries, Duke Capital), a wholly owned subsidiary of Duke Energy Corporation (Duke Energy), is a leading energy company located in the Americas with a real estate subsidiary. On March 1, 2004, Duke Capital changed its form of organization from a corporation to a Delaware limited liability company by effecting a conversion pursuant to Section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company Act. Pursuant to the conversion, all rights and liabilities of Duke Capital Corporation in its previous corporate form vested in Duke Capital as a limited liability company. Duke Capital owns corporations who file as part of the Duke Energy consolidated federal income tax return and file their own respective foreign and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of Duke Capital. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Capital and all majority-owned subsidiaries where Duke Capital has control, and those variable interest entities where Duke Capital is the primary beneficiary.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present Duke Capital’s financial position and results of operations. Amounts reported in the interim Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, the timing of maintenance on electric generating units, pipelines and gas processing facilities, changes in mark-to-market valuations, changing commodity prices and other factors. These Consolidated Financial Statements and other information included in this quarterly report should be read in conjunction with the Consolidated Financial Statements and Notes in Duke Capital’s Form 10-K for the year ended December 31, 2004.

Use of Estimates.To conform to generally accepted accounting principles (GAAP) in the United States (U.S.), management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Reclassifications and Revisions. The accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2004 reflects a reclassification of instruments used in Duke Capital’s cash management program from cash and cash equivalents to short-term investments of $1,684 million and $608 million as of June 30, 2004 and December 31, 2003, respectively. This reclassification was made in order to present certain auction rate securities and other highly-liquid instruments as short-term investments rather than as cash equivalents due to the stated tenor of the maturities of these investments.

Certain other prior period amounts have also been reclassified to conform to the presentation for the current period.

2. Stock-Based Compensation

Duke Capital and its subsidiaries are allocated stock-based compensation expense from Duke Energy as certain of its employees participate in Duke Energy’s stock-based compensation programs. Duke Energy accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and the Financial Accounting Standards Board (FASB) Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” The following table illustrates the effect on net income for Duke Capital, if Duke Energy had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation” to all stock-based compensation awards and reflects the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment to FASB Statement No. 123).”

Pro Forma Stock-Based Compensation

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Net income, as reported	$	128		$	277		$	779		$	373
Add: stock-based compensation expense included in reported net income, net of related tax effects		7			2			13			5
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(7	)		(4	)		(13	)		(10	)
Pro forma net income	$	128		$	275		$	779		$	368

5

PART I

DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

3. Inventory

Inventory is recorded at the lower of cost or market value, primarily using the average cost method.

Inventory

	June 30,		December 31,
	2005		2004
	(in millions)
Materials and supplies	$	144	$	144
Natural gas		243		312
Petroleum products		89		74
Total inventory	$	476	$	530

4. Debt and Credit Facilities

In December 2004, Duke Capital reached an agreement to sell its partially completed Grays Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC (see Note 7). In 2004, Duke Capital also terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Capital in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

In August 2005, Duke Capital’s International Energy business unit issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $35 million (in U.S. dollar equivalents) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

Available Credit Facilities and Restrictive Debt Covenants. During the six-month period ended June 30, 2005, Duke Capital’s consolidated credit capacity increased by approximately $750 million compared to December 31, 2004. Duke Capital and Duke Energy Field Services LLC (DEFS) renewed and replaced certain of their credit facilities at higher levels to provide additional credit capacity. Duke Capital added a new $100 million, 364 day bilateral credit facility to provide additional letter of credit issuing capacity and increased its expiring 364 day letter of credit facility by $200 million. In addition, Duke Capital added three new 364 day credit facilities totaling $260 million to provide additional credit support. DEFS increased its expiring 364 day credit facility by $200 million. Westcoast Energy Inc. (Westcoast) and Union Gas Limited (Union Gas) renewed and replaced their credit facilities at existing levels. Duke Capital amended its multi-year syndicated facility to extend the expiration date.

The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Duke Capital’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2005, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

6

PART I

DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

Credit Facilities Summary as of June 30, 2005

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
				Commercial Paper		Letters of Credit		Total
	(in millions)
Duke Capital LLC
$800 364-day syndicated (a), (b)	June 2006
$600 multi-year syndicated (a), (b), (d)	June 2009
$130 three-year bi-lateral (b)	October 2007
$120 multi-year bi-lateral (b)	July 2009
$100 364-day bi-lateral (b)	June 2006
$260 364-day bi-laterals (a), (b)	June 2006
Total Duke Capital LLC		$	2,010	$	—	$	781	$	781
Westcoast Energy Inc.
$81 364-day syndicated (b), (e)	June 2006
$162 multi-year syndicated (b), (c), (f)	June 2010
Total Westcoast Energy Inc.			243		—		—		—
Union Gas Limited
$243 364-day syndicated (g), (h)	June 2006		243		—		—		—
Duke Energy Field Services LLC
$450 multi-year syndicated (i), (j), (k)	April 2010		450		—		—		—
Total		$	2,946	$	—	$	781	$	781

(a) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(c) In June 2005, credit facility expiration date was extended from June 2007 to June 2010.

(d) In June 2005, credit facility expiration date was extended from June 2007 to June 2009.

(e) Credit facility is denominated in Canadian dollars totaling 100 million Canadian dollars.

(f) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars.

(g) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars totaling 300 million Canadian dollars.

(h) Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

(i) Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date.

(j) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 60%.

(k) Credit facility contains an interest coverage covenant.

5. Employee Benefit Obligations

Duke Capital and its subsidiaries participate in Duke Energy’s non-contributory defined benefit retirement plan. Duke Capital’s net periodic pension benefit as allocated by Duke Energy for its U.S. plan was $5 million and $7 million for the three months ended June 30, 2005 and 2004, respectively. Duke Capital’s net periodic pension benefit as allocated by Duke Energy for its U.S. plan was $10 million and $14 million for the six months ended June 30, 2005 and 2004, respectively.

The following table shows the components of the net periodic pension costs for Westcoast Canadian retirement plans.

Components of Net Periodic Pension Costs for Westcoast

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Service cost	$	2		$	2		$	4		$	4
Interest cost on projected benefit obligation		8			6			15			13
Expected return on plan assets		(7	)		(6	)		(13	)		(12	)
Amortization of loss		1			1			2			1
Net periodic pension costs	$	4		$	3		$	8		$	6

7

PART I

DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

Duke Energy’s policy is to fund amounts for its U.S. retirement plan on an actuarial basis to provide sufficient assets to meet benefit payments to plan participants. Duke Energy has not made contributions to its U.S. retirement plan for the three and six months ended June 30, 2005 and does not anticipate making a contribution to the U.S. retirement plan for the remainder of 2005.

Westcoast’s policy is to fund its defined benefit (DB) retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefit payments. Contributions to the defined contribution (DC) retirement plans are determined in accordance with the terms of the plans. Duke Energy has contributed $8 million and $19 million to the Westcoast DB plans for the three and six months ended June 30, 2005, respectively. Duke Energy anticipates that it will make total contributions of approximately $37 million in 2005. Duke Energy has contributed $1 million and $2 million to the Westcoast DC plans for the three and six months ended June 30, 2005, respectively, and anticipates that it will make total contributions of approximately $3 million in 2005.

Duke Capital and most of its subsidiaries, in conjunction with Duke Energy, provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Duke Capital’s net periodic post-retirement costs as allocated by Duke Energy were $4 million for both the three months ended June 30, 2005 and 2004. The costs allocated by Duke Energy were $9 million and $11 million for the six months ended June 30, 2005 and 2004, respectively.

The following table shows the components of the net periodic post-retirement benefit costs for the Westcoast other post-retirement benefit plans.

Components of Net Periodic Post-Retirement Benefit Costs for Westcoast

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
	(in millions)
Service cost benefit	$	—	$	1	$	1	$	1
Interest cost on accumulated post- retirement benefit obligation		1		1		2		2
Amortization of loss		1		—		1		1
Net periodic post-retirement benefit costs	$	2	$	2	$	4	$	4

Duke Energy also sponsors, and Duke Capital participates in, an employee savings plan that covers substantially all U.S. employees. Duke Capital expensed plan contributions allocated by Duke Energy of $4 million and $5 million for the three months ended June 30, 2005 and 2004, respectively. Duke Capital expensed plan contributions allocated by Duke Energy of $12 million for both the six months ended June 30, 2005 and 2004.

6. Comprehensive Income and Accumulated Other Comprehensive Income (AOCI)

Comprehensive Income. Comprehensive income includes net income and all other non-owner changes in equity.

Total Comprehensive Income

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Net Income	$	128		$	277		$	779		$	373
Other comprehensive income
Foreign currency translation adjustments		10			(235	)		(5	)		(278	)
Net unrealized gains on cash flow hedges (a)		94			44			238			167
Reclassification into earnings from cash flow hedges (b)		(58	)		(63	)		1			(57	)
Other comprehensive income (loss), net of tax		46			(254	)		234			(168	)
Total Comprehensive Income	$	174		$	23		$	1,013		$	205

(a) Net unrealized gains on cash flow hedges, net of $53 million and $0 tax expense for the three months ended June 30, 2005 and 2004, respectively, and $126 million and $67 million tax expense for the six months ended June 30, 2005 and 2004, respectively.

(b) Reclassification into earnings from cash flow hedges, net of $31 million and $19 million tax benefit for the three months ended June 30, 2005 and 2004, respectively, and $1 million tax expense and $17 million tax benefit for the six months ended June 30, 2005 and 2004, respectively.

8

PART I

DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

Accumulated Other Comprehensive Income.The following table shows the components of and changes in AOCI.

Components of and Changes in AOCI

	Foreign Currency Adjustments			Net Gains on Cash Flow Hedges		Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income
	(in millions)
Balance as of December 31, 2004	$	534		$	536	$	(21	)	$	1,049
Other comprehensive income changes year-to-date (net of tax expense of $127)		(5	)		239		—			234
Balance as of June 30, 2005	$	529		$	775	$	(21	)	$	1,283

7. Acquisitions and Dispositions

Acquisitions. Duke Capital consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in Emerging Issues Task Force (EITF) Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items.

On May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they have entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $4 billion. The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. For further discussion of the status of regulatory filings see Note 13. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions. Among other things, the merger agreement contemplates potential transactions that could involve the transfer of certain assets out of Duke Capital in connection with the merger. However, any potential transactions involving assets of Duke Capital and related consideration remain subject to change.

In April 2005, Duke Capital’s Natural Gas Transmission business unit agreed to acquire natural gas storage and pipeline assets in southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for $62 million. Upon closing of this transaction, which was completed in August 2005, Natural Gas Transmission owns 100% of Saltville Storage.

In the second quarter 2005, United Bridgeport Energy, LLC (UBE), the owner of a 33 1/3 % interest in Bridgeport Energy, LLC (Bridgeport), exercised its “put right” requiring Duke Energy North America (DENA) to purchase UBE’s interest in Bridgeport as provided for in the LLC Agreement. DENA and UBE are currently negotiating the purchase price of UBE’s ownership interest. Upon closing of this transaction, DENA will own 100% of Bridgeport.

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DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

Dispositions.For the three months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $20 million in proceeds, and pre-tax gains of $6 million recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. For the six months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $1.3 billion in net proceeds, pre-tax gains of $32 million recorded in (Losses) Gains on Sales of Other Assets, net and pre-tax gains of approximately $1.2 billion recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 10, and commercial and multi-family real estate sales by Crescent Resources LLC (Crescent) which are discussed separately below. Significant sales of other assets and equity investments during the six months ended June 30, 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which have been classified as Gains on Sales of Equity Investments in the Consolidated Statement of Operations for the six months ended June 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the six months ended June 30, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP.

Additionally, in July 2005, Duke Energy caused a Duke Capital subsidiary to complete the previously announced agreement with ConocoPhillips, Duke Capital’s co-equity owner in DEFS, to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. Duke Capital has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion in cash and assets from ConocoPhillips and DEFS. The DEFS disposition transaction includes the transfer to Duke Capital of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction, as previously announced, was anticipated to include ConocoPhillips’ interest in the Empress System gas processing and natural gas liquids marketing business (Empress System). However, the transfer of the Empress System to Duke Capital was delayed pending damage repairs to the assets from a recent windstorm and as a result ConocoPhillips has transferred an equivalent value of cash to Duke Capital in July 2005. The Empress System was subsequently transferred to Duke Capital in August 2005 and cash of approximately $230 million was remitted to ConocoPhillips as consideration for the transfer. Subsequent to the DEFS disposition transaction, DEFS will no longer be consolidated into Duke Capital’s historical consolidated financial statements and will be accounted for by Duke Capital as an equity method investment. See Note 12 for the impacts of this transaction on certain cash flow hedges. The DEFS Canadian natural gas gathering and processing facilities and the Empress System will be included in Duke Capital’s Natural Gas Transmission business unit.

• DENA asset sales during the six month period ended June 30, 2005 totaled approximately $34 million in net proceeds. Those sales resulted in pre-tax gains of $27 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Total sales were driven principally by the sale of Grays Harbor to an affiliate of Invenergy LLC resulting in a pre-tax gain of approximately $21 million (excluding any potential contingent consideration), which was completed in the first quarter of 2005.

• Additional asset and business sales during the six month period ended June 30, 2005 totaled approximately $18 million in net proceeds. These sales resulted in net pre-tax gains of $5 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations.

For the three months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $26 million of proceeds and $12 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $77 million of proceeds and $54 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales consisted of several “legacy” land sales.

For the three months ended June 30, 2004, the sale of other assets resulted in approximately $33 million in proceeds, and net losses of $13 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. For the six months ended June 30, 2004, the sale of other assets resulted in approximately $107 million in proceeds, and net losses of $365 million

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Notes To Consolidated Financial Statements—(Continued)

recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. Significant sales of other assets and equity investments during the six months ended June 30, 2004 are as follows:

• As a result of the marketing efforts related to DENA’s eight plants in the southeastern U.S., Duke Capital classified those assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million in the first quarter of 2004, which represented the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in (Losses) Gains on Sales of Other Assets, net in the first quarter of 2004 Consolidated Statement of Operations. The fair value of the plants was based upon the anticipated price of approximately $475 million agreed upon with KGen Partners LLP (KGen) and announced on May 4, 2004. The sale closed in August 2004 and the actual sales price consisted of $420 million cash and a $48 million note receivable with principal and interest due no later than seven years and six months after the closing date. The entire balance of the note, including interest, was repaid by KGen in the first quarter of 2005. The agreement included the sale of all of Duke Capital’s merchant generation assets in the southeastern U.S. The results of operations related to these assets are not reported within Discontinued Operations due to Duke Capital’s significant continuing involvement in the future operations of the plants including a long-term operating agreement for one of the plants and retention of certain guarantees related to these assets.

• In May 2004, Duke Capital reached an agreement to sell its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V, (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico for approximately $60 million. Duke Capital recorded a $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statement of Operations, related to a note receivable from Cantarell, in the first quarter of 2004 in anticipation of this sale. The sale closed in the third quarter of 2004.

For the three months ended June 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $136 million of proceeds and $62 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $303 million of proceeds, and $121 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Significant sales included the Potomac Yard retail center in the Washington, D.C. area in March 2004, the Alexandria land tract in the Washington, D.C. area in June 2004 and several large “legacy” land sales closed in the first quarter of 2004.

8. Member’s Equity and Related Party Transactions

During the six months ended June 30, 2005, Duke Capital distributed $1,050 million to its parent, Duke Energy, to principally provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the sale by DEFS of TEPPCO GP and Duke Capital’s sale of its limited partner interest in TEPPCO LP.

During 2004, $267 million of cash advances were received by Duke Capital from Duke Energy. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Duke Capital classified the $267 million as an addition to Member’s Equity. This forgiveness is presented as a non-cash financing activity in the Consolidated Statement of Cash Flows for the six months ended June 30, 2005.

In April 2005, Duke Capital received a $269 million capital contribution from Duke Energy, which Duke Capital classified as an addition to Member’s Equity. Additionally, during the second quarter of 2005, Duke Capital received $61 million in advances from Duke Energy. These transactions are presented as a component of net cash used in financing activities in the Consolidated Statement of Cash Flows for the six months ended June 30, 2005.

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DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

Balances due to or due from Duke Capital affiliated entities included in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are as follows:

Assets/(Liabilities)	June 30,			December 31,
	2005			2004
	(in millions)
Advances receivable (a)	$	326		$	214
Taxes receivable/(payable) (b)	$	(177	)	$	13
Accounts payable (c)	$	(41	)	$	(34	)
Other current liabilities (d)	$	(13	)	$	—

(a) Advances receivable are classified as Other within Investments and Other Assets on the Consolidated Balance Sheets. The advances do not bear interest, are carried as open accounts and are not segregated between current and non-current amounts.

(b) The June 30, 2005 balances are classified as Taxes Accrued and the December 31, 2004 balances are classified as Other Current Assets in the Consolidated Balance Sheets.

(c) The balances are classified as Accounts Payable on the Consolidated Balance Sheets.

(d) The balances are classified as Other Current Liabilities on the Consolidated Balance Sheets.

9. Severance

During 2002, Duke Capital communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and will apply to individuals notified of layoffs between that date and January 1, 2006. As of June 30, 2005, there are no significant remaining amounts to be paid under these severance plans. Provision for severance is included in Operation, Maintenance and Other in the Consolidated Statements of Operations.

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Notes To Consolidated Financial Statements—(Continued)

10. Discontinued Operations and Assets Held for Sale

The following table summarizes the results classified as Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Discontinued Operations (in millions)
			Net Operating Income									Net Gain on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain on Dispositions		Income Tax Expense		Gain on Dispositions, Net of Tax
Three Months Ended June 30, 2005
DENA	$	23	$	(4	)	$	(2	)	$	(2	)	$	—	$	—	$	—
International Energy		—		2			1			1			—		—		—
Total consolidated	$	23	$	(2	)	$	(1	)	$	(1	)	$	—	$	—	$	—
Three Months Ended June 30, 2004
Field Services	$	15	$	(1	)	$	(1	)	$	—		$	—	$	—	$	—
DENA		58		(2	)		(1	)		(1	)		—		—		—
International Energy		16		(3	)		2			(5	)		39		9		30
Other		1		2			1			1			—		—		—
Total consolidated	$	90	$	(4	)	$	1		$	(5	)	$	39	$	9	$	30
Six Months Ended June 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—	$	—	$	—
DENA		57		(4	)		(2	)		(2	)		—		—		—
International Energy		—		4			1			3			—		—		—
Total consolidated	$	61	$	—		$	(1	)	$	1		$	—	$	—	$	—
Six Months Ended June 30, 2004
Field Services	$	51	$	1		$	—		$	1		$	2	$	1	$	1
DENA		58		(2	)		(1	)		(1	)		—		—		—
International Energy		82		3			1			2			295		27		268
Other		1		2			1			1			—		—		—
Total consolidated	$	192	$	4		$	1		$	3		$	297	$	28	$	269

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Notes To Consolidated Financial Statements—(Continued)

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale

	June 30,		December 31,
	2005		2004
	(in millions)
Current assets	$	15	$	40
Investments and other assets		30		12
Net property, plant and equipment		33		72
Total assets held for sale	$	78	$	124
Current liabilities	$	—	$	30
Long-term debt		14		14
Total liabilities associated with assets held for sale	$	14	$	44

Field Services

In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, Duke Capital’s Field Services business unit classified these assets as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2004. The book value of those assets was written down by $4 million ($3 million net of minority interest) to $10 million in December 2004, which represents the estimated fair value less cost to sell. The results of operations related to these assets were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.

In September 2004, Field Services recorded a pre-tax impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s assessment of some additional gathering, processing, compression and transportation assets in Wyoming being held for sale. The estimated fair value of these assets less cost to sell was $27 million and they were classified as Assets Held For Sale in the Consolidated Balance Sheets as of December 31, 2004. The after-tax loss and results of operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. In the first quarter of 2005, Field Services sold these assets for proceeds of approximately $28 million.

In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third-party purchaser for a sales price of approximately $62 million, which approximated these assets’ carrying value. The results of operations related to these assets were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

DENA

On September 21, 2004, DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving would purchase DENA’s 75% interest in Bayside Power L.P. (Bayside). As a result of the above agreement, DENA presented the $54 million of assets and $14 million of liabilities as of June 30, 2005 and $59 million of assets and $19 million of liabilities as of December 31, 2004 related to Bayside as Assets Held For Sale in the Consolidated Balance Sheets. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was approximately $20 million at June 30, 2005 and $19 million at December 31, 2004. Bayside was consolidated with the adoption of FASB Interpretation (FIN) No. 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51”, on March 31, 2004. Therefore, Bayside’s operating results after March 31, 2004 are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment. The sale of Bayside closed on July 13, 2005. The after-tax gain on this sale will be included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations in the third quarter of 2005.

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Notes To Consolidated Financial Statements—(Continued)

International Energy

In order to eliminate exposure to international markets outside of Latin America and Canada, Duke Capital’s International Energy business unit decided in 2003 to pursue a possible sale or initial public offering of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after-tax loss of $233 million during the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. Fair value of the business was estimated based primarily on comparable third-party sales and analysis from outside advisors. This after-tax loss was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations.

In the first quarter of 2004, International Energy determined it was likely that a bid in excess of the originally determined fair value would be accepted and thus recorded a $238 million after-tax gain related to International Energy’s Asia-Pacific Business. The after-tax gain was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations and restored the loss recorded during the fourth quarter of 2003.

In the second quarter of 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion. This resulted in recording an additional $40 million after-tax gain in the second quarter of 2004. The after-tax gain was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific Business.

In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $57 million as of June 30, 2005 and $68 million as of December 31, 2004. This receivable is included in Receivables in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004. During the three months ended June 30, 2004, International Energy recorded a $14 million (approximately $9 million after tax) allowance for the note based on management’s assessment of the probability of not collecting the entire note. The after-tax loss was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations.

The results of operations related to these operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. In the case Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the projects as “discontinued operations” as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. In the second quarter of 2005, Crescent classified two commercial properties with a fair value less cost to sell of approximately $24 million as Assets Held for Sale in the Consolidated Balance Sheets.

Other

During 2003, Duke Capital decided to exit the merchant finance business conducted by Duke Capital Partners (DCP). The sale or collection of all of DCP’s notes receivable was completed during 2004. DCP’s operating results are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

11. Business Segments

Duke Capital operates the following business units: Natural Gas Transmission, Field Services, DENA, International Energy and Crescent. Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the business units are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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Notes To Consolidated Financial Statements—(Continued)

The remainder of Duke Capital’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, certain discontinued hedges, DukeNet Communications, LLC, Duke Capital’s wholly owned, captive insurance subsidiary, and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD).

During the first quarter of 2005, Duke Capital discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 12 for further discussion.

Duke Capital’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Capital’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).

On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Capital, so the associated realized and unrealized gains and losses from foreign currency remeasurement and interest and dividend income on those balances, are excluded from the segments’ EBIT.

Transactions between reportable segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.

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Notes To Consolidated Financial Statements—(Continued)

Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Three Months Ended June 30, 2005
Natural Gas Transmission	$	691	$	58		$	749		$	302
Field Services		2,842		46			2,888			166
DENA		451		12			463			(56	)
International Energy		182		—			182			86
Crescent		112		—			112			39
Total reportable segments		4,278		116			4,394			537
Other		36		(8	)		28			(12	)
Eliminations		—		(108	)		(108	)		—
Interest expense		—		—			—			(223	)
Interest income and other (a)		—		—			—			36
Total consolidated	$	4,314	$	—		$	4,314		$	338
Three Months Ended June 30, 2004
Natural Gas Transmission	$	635	$	53		$	688		$	311
Field Services		2,322		19			2,341			95
DENA		626		20			646			(38	)
International Energy		147		—			147			68
Crescent		101		—			101			87
Total reportable segments		3,831		92			3,923			523
Other		20		17			37			30
Eliminations		—		(109	)		(109	)		—
Interest expense		—		—			—			(262	)
Interest income and other (a)		—		—			—			41
Total consolidated	$	3,851	$	—		$	3,851		$	332

(a) Other includes foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

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Notes To Consolidated Financial Statements—(Continued)

Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Six Months Ended June 30, 2005
Natural Gas Transmission	$	1,814	$	110		$	1,924		$	709
Field Services		5,380		182			5,562			1,087
DENA		918		13			931			(91	)
International Energy		350		—			350			154
Crescent		176		—			176			91
Total reportable segments		8,638		305			8,943			1,950
Other		67		(105	)		(38	)		(93	)
Eliminations		—		(200	)		(200	)		—
Interest expense		—		—			—			(446	)
Interest income and other (a)		—		—			—			61
Total consolidated	$	8,705	$	—		$	8,705		$	1,472
Six Months Ended June 30, 2004
Natural Gas Transmission	$	1,617	$	109		$	1,726		$	709
Field Services		4,598		96			4,694			186
DENA		1,228		42			1,270			(595	)
International Energy		301		—			301			97
Crescent		139		—			139			147
Total reportable segments		7,883		247			8,130			544
Other		45		34			79			57
Eliminations		—		(281	)		(281	)		—
Interest expense		—		—			—			(535	)
Interest income and other (a)		—		—			—			52
Total consolidated	$	7,928	$	—		$	7,928		$	118

(a) Other includes foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

Segment assets in the following table are net of intercompany advances, intercompany notes receivable, certain intercompany current assets, intercompany derivative assets and investments in subsidiaries.

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Notes To Consolidated Financial Statements—(Continued)

Segment Assets

	June 30, 2005			December 31, 2004
	(in millions)
Natural Gas Transmission	$	17,079		$	17,106
Field Services		7,523			6,810
DENA		7,538			7,255
International Energy		3,576			3,329
Crescent		1,478			1,315
Total reportable segments		37,194			35,815
Other		476			1,142
Reclassifications and eliminations (a)		(147	)		(48	)
Total consolidated assets	$	37,523		$	36,909

(a) Represents reclassification of federal tax balances in consolidation and the elimination of intercompany assets, such as accounts receivable and interest receivable.

Segment assets include goodwill of $4,106 million as of June 30, 2005 and $4,148 million as of December 31, 2004, with $3,343 million allocated to Natural Gas Transmission, $496 million to Field Services, $260 million to International Energy and $7 million to Crescent as of June 30, 2005. The $42 million decrease from December 31, 2004 to June 30, 2005 was related solely to foreign currency exchange rate fluctuations of $55 million at Natural Gas Transmission and $2 million at Field Services, partially offset by an increase of $15 million at International Energy.

12. Risk Management Instruments

The following table shows the carrying value of Duke Capital’s derivative portfolio as of June 30, 2005, and December 31, 2004.

Derivative Portfolio Carrying Value

	June 30, 2005			December 31, 2004
	(in millions)
Hedging	$	1,318		$	815
Trading		(7	)		20
Undesignated		(354	)		(264	)
Total	$	957		$	571

The amounts in the table above represent the combination of assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Capital’s Consolidated Balance Sheets. All amounts represent current fair value, except that the net asset amounts for hedging include assets of $94 million as of June 30, 2005 and $160 million as of December 31, 2004, that were frozen upon Duke Capital’s initial application of the normal purchases and normal sales exception to its forward power sales contracts as of July 1, 2001. These asset values will amortize as they settle over approximately five years.

The $503 million increase in the hedging derivative portfolio carrying value is due primarily to increases in forward natural gas prices, partially offset by the realization of natural gas hedge gains as well as other hedge activity.

The $90 million decrease in the undesignated derivative portfolio fair value is due primarily to mark-to-market of certain contracts held by Duke Capital related to Field Services’ commodity price risk. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see Note 7), Duke Capital discontinued hedge accounting for certain contracts held by Duke Capital related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. As a result, approximately $120 million of unrealized pre-tax losses previously recorded in AOCI related to these contracts has been recognized in earnings by Duke Capital in the six months ended June 30, 2005. These charges have been classified as a component of Impairment and Other Charges in the Consolidated Statement of Operations. Since discontinuance of

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hedge accounting, these contracts have been marked-to market in the Consolidated Statement of Operations, resulting in the recognition of approximately $20 million and $130 million of additional realized and unrealized pre-tax losses, classified as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other Revenues in the Consolidated Statement of Operations for the three and six months ended June 30, 2005, respectively. The decrease in the undesignated derivative portfolio fair value is partially offset by certain contract terminations at DENA.

Included in Other Current Assets in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are collateral assets of approximately $392 million and $247 million, respectively, which represents cash collateral posted by Duke Capital with other third parties. This increase in cash collateral posted by Duke Capital is primarily due to increases to forward market prices of power. Included in Other Current Liabilities in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are collateral liabilities of approximately $444 million and $429 million, respectively, which represent cash collateral posted by other third parties to Duke Capital.

During the first quarter of 2005, Duke Capital settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast on their scheduled maturity and paid approximately $162 million. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Duke Capital’s investment in Westcoast occurs.

Commodity Cash Flow Hedges.Some Duke Capital subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Capital closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Capital uses commodity instruments, such as swaps, futures, forwards and options as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Capital is hedging exposures to the price variability of these commodities for a maximum of 12 years.

As of June 30, 2005, $438 million of the pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in a separate component of Members’ Equity, in AOCI, and are expected to be recognized in 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 will likely change prior to its reclassification into earnings.

The ineffective portion of commodity cash flow hedges resulted in the recognition of a loss of approximately $11 and $30 million in the three and six months ended June 30, 2005, respectively, as compared to a gain of $2 and $5 million in the three and six months ended June 30, 2004, respectively.

13. Regulatory Matters

Duke Energy Merger with Cinergy. As discussed in Note 7, on May 9, 2005, Duke Energy and Cinergy announced they have entered into a definitive merger agreement. Approval of the merger by several federal and state agencies is required. During the second quarter of 2005, Duke Energy and Cinergy filed petitions or applications for approval of the merger with the Indiana Utility Regulatory Commission and the Public Utilities Commission of Ohio. In July 2005, Duke Energy and Cinergy filed an application for approval of the merger with the Federal Energy Regulatory Commission (FERC), and Duke Energy filed applications for the approval of the merger with the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC). In August 2005, Duke Energy and Cinergy filed an application for the approval of the merger with the Kentucky Public Service Commission. During the third quarter of 2005, Duke Energy and Cinergy expect to file the remaining required petitions or applications for approval or pre-approval of the merger.

Natural Gas Transmission. FERC Accounting Order. In June 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order is effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and is expected to increase annual expenses within Natural Gas Transmission by approximately $15 million to $20 million. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule are not impacted.

Rate Related Information.In December 2004, the Ontario Energy Board (OEB) approved the 2005 rates for Union Gas. The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the 9.63% benchmark return on equity (ROE), normalized for weather, will be shared equally between ratepayers and Union Gas. No rate relief will be

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provided if Union Gas earns below the allowed ROE, normalized for weather. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $8 million during the six months ended June 30, 2005.

The OEB also directed Union Gas to provide direction as to how it will proceed with setting 2006 rates, including the use of an earnings sharing mechanism. Union Gas responded to this directive by recommending the use of the same earnings sharing mechanism as found appropriate by the Board for 2005 rates, with a request for a rate increase. The OEB indicated in May 2005 that it was prepared to consider Union Gas’ request, but required an application and supporting evidence, which Union Gas provided to the OEB on July 29, 2005.

On March 30, 2005, the OEB issued a report containing plans for refining natural gas sector regulation. The OEB has endorsed the concept of a multi-year incentive regulation plan. It has scheduled a series of proceedings over the next three years to establish key parameters underpinning this framework. Union Gas will participate in these proceedings.

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement has been filed with FERC for its review and approval. FERC is expected to act on the settlement agreement prior to the end of 2005.

Management believes that the results of these matters will have no material adverse effect on Duke Capital’s future consolidated results of operations, cash flows or financial position.

International Energy. Brazil Regulatory Environment. In 2004, a new energy law enacted in Brazil changed the electricity sector’s regulatory framework. The new energy law created a regulated and non-regulated market that coexist. The regulated market consists of auctions conducted by the government for the sale of power to distribution companies, who are required to fully contract their estimated electricity demand, principally through the regulated auctions. In the non-regulated market, generators, traders and non-regulated customers are permitted to enter into bilateral electricity purchase and sale contracts. The first regulated auction was held December 7, 2004, and the second on April 2, 2005. In those auctions, distribution companies contracted for their estimated electricity demand for the period from 2005 to 2016. The contracts offered in the auctions were eight-year contracts with delivery periods commencing in each of the years 2005 through 2008. Duke Capital’s Brazilian affiliate, Duke Energy International, Geracao Paranapanema S.A. (Paranapanema), participated in these auctions as a seller of electricity and elected to commit to eight-year contracts for delivery of 214 Megawatts (MW) beginning in 2005, 58 MW for delivery beginning in 2006, and 218 MW for delivery beginning in 2007. Paranapanema elected not to commit any capacity to the 2008 contract, and withheld some available capacity from the 2006 and 2007 contracts, due to low pricing and in order to preserve the capability to capture higher value alternatives in the future.

14. Commitments and Contingencies

Environmental

Duke Capital is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. Like others in the energy industry, Duke Capital and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Capital operations, sites formerly owned or used by Duke Capital entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Capital or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Capital may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Duke Capital’s three natural

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gas-fired generating facilities in California are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to provide information needed to determine necessary facility-specific modifications and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures are determined and approved by regulators, a facility will typically have five or more years to implement the measures. Due to the wide range of measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Capital is not able to estimate its cost for complying with the rule at this time.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $60 million as of June 30, 2005. These accruals represent Duke Capital’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Litigation

Western Energy Litigation. Since 2000, plaintiffs have filed 48 lawsuits in four western states against Duke Capital affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Eleven suits have been dismissed on filed rate and/or federal preemption grounds. The plaintiffs in these dismissed suits appealed, and the U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit petitioned the U.S. Supreme Court for certiorari and the Court invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted. On May 27, 2005, the U.S. Solicitor General recommended that certiorari be denied. On June 27, 2005, the U.S. Supreme Court denied certiorari.

• In July 2004, Duke Energy reached an agreement in principle resolving the class-action litigation involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement is part of a more comprehensive settlement involving FERC refunds and other proceedings related to the western energy markets during 2000-2001 (the California Settlement). The class action portion of the settlement was subject to court approval, but FERC approved all remaining provisions of the settlement in December 2004. As part of the California Settlement, Duke Capital agreed to provide approximately $208 million in cash and credits to various parties involved in the settlement. The parties agreed to forgo all claims relating to refunds or other monetary damages for sales of electricity during the settlement period (January 1, 2000 through June 20, 2001), and claims alleging Duke Capital subsidiaries received unjust or unreasonable rates for the sale of electricity during the settlement period. In December 2004, Duke Capital tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. This remaining amount, which is fully reserved, will be paid upon court approval of the class-action settlement. On July 22, 2005, the Superior Court for San Diego County entered an order granting preliminary approval of the class-action settlement and authorizing notice of the proposed settlements to be sent to the respective class members. A hearing on final approval of the class-action settlements is presently scheduled for December 2005.

• Suits filed on behalf of electricity ratepayers in other western states, on behalf of entities that purchased electricity directly from a generator and on behalf of natural gas purchasers, remain pending. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with these lawsuits, but Duke Capital does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with Duke Energy Trading and Marketing, LLC (DETM, Duke Capital’s 60/40 joint venture with ExxonMobil Corporation) relating to amounts owed in connection with the termination of bilateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in

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excess of $90 million. Based on the level of damages claimed by the plaintiff and Duke Capital’s assessment of possible outcomes in this matter, Duke Capital does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Western Energy Regulatory Matters and Investigations. The U.S. Attorney’s Office in San Francisco served a grand jury subpoena on Duke Energy in 2002 seeking information relating to possible manipulation of the California electricity markets, including potential antitrust violations. Duke Capital does not believe the outcome of this investigation will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Trading Related Litigation. By letter dated April 16, 2004, Duke Energy received notice that a shareholder reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same “round trip” trades issues raised in the shareholder lawsuits dismissed by the courts in 2003 and affirmed on appeal, the notice stated that the shareholder intended to initiate derivative shareholder litigation within 90 days from the date of the letter if Duke Energy did not initiate litigation within the stated timeframe. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims. By letter dated January 21, 2005, another shareholder reactivated a 2002 litigation demand. The reactivated demand arises out of the same issues that were raised in the April 16 reactivated demand as well as matters that were the subject of the California Settlement. On March 16, 2005, the special committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims.

Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants. On January 25, 2005, the plaintiffs filed a motion for class certification; defendants are opposing the motion which has not to date been scheduled for hearing. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.

On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Capital affiliates and other energy companies seeking class action certification on behalf of indirect purchasers of natural gas who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.

Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the Securities and Exchange Commission (SEC) and to grand jury subpoenas issued by the U.S. Attorney’s office in Houston, Texas. The information requests and subpoenas sought documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in 2002 that the SEC formalized its trading-related investigation and is cooperating with the SEC. Following discussions with the SEC staff, Duke Energy made an offer of settlement in April 2005 to resolve the issues that are the subject of the SEC’s investigation regarding conduct that occurred in 2000 through June 2002. The terms of the offer included issuance of an order to Duke Energy to cease and desist from violating internal controls and books and records requirements under Sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, but did not include a penalty or finding of fraud. Prior to 2005, Duke Energy, Duke Capital and their subsidiaries took actions to remediate the issues that have been raised in the SEC’s investigation regarding internal controls. The offer of settlement was approved by the SEC in July 2005.

In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to

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the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Capital recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the three indicted former DETMI employees pled guilty to a books and records violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls.

Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and Duke Capital is unable to express an opinion regarding the probable outcome at this time.

In February 2005, the Commodity Futures Trading Commission initiated a civil action against a former DETM trader asserting charges of delivering false reports and attempted manipulation of prices through index price reporting. Neither Duke Energy nor Duke Capital is named in this action.

In July 2005, a plaintiff indicated that it intends to file suit in state court in Kansas against Duke Capital affiliates, as well as other energy companies, claiming that it was harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and by entering into unlawful arrangements and agreements. The plaintiff claims the defendants violated Kansas’ antitrust laws. The plaintiff did not specify the amount of plaintiff’s purported damages. No lawsuit on this matter has been filed as of the date of this Form 10-Q. Duke Capital cannot predict the outcome of this matter at this time.

Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG), a Duke Capital subsidiary, claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $600 million. In 2003, an arbitration panel issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The panel also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The hearing on damages issues is scheduled to commence in September 2005.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. Cross motions for partial summary judgment regarding the letter of credit issue have been filed and are pending. No trial date has been set. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with the Sonatrach and Citrus matters.

ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other subsidiaries of Duke Capital. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. ExxonMobil seeks to recover actual damages, plus attorneys’ fees and exem - -

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plary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that ExxonMobil breached its Ventures obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of ExxonMobil’s claims. ExxonMobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. The arbitration panel has scheduled briefing on the reconsideration motion and postponed the commencement date of the arbitration hearing from January 2006 to October 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain ExxonMobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Ventures and wrongfully failed to assume certain related gas supply agreement with other parties. A hearing in the Canadian arbitration, originally scheduled to commence in August 2005 in Calgary, Canada, has tentatively been rescheduled for March 2006. It is not possible to predict with certainty the damages that might be incurred by Duke Capital or any of its subsidiaries as a result of these matters.

Other Litigation and Legal Proceedings. Duke Capital and its subsidiaries are involved in other legal, tax and regulatory proceedings in various forums regarding performance, contracts, royalty disputes, mismeasurement and mispayment claims (some of which are brought as class actions), and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Duke Capital has exposure to certain legal matters that are described herein. As of June 30, 2005, Duke Capital has recorded reserves of approximately $130 million for these proceedings and exposures. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

Duke Capital expenses legal costs related to the defense of loss contingencies as incurred.

15. Guarantees and Indemnifications

Duke Capital and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Capital enters into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the prime contractor to the U.S. Department of Energy (DOE) under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of June 30, 2005, Duke Capital, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

The Prime Contract consists of a “Base Contract” phase and three successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of June 30, 2005, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and an initial segment of the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Capital estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of June 30, 2005, Duke Capital had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.

In connection with the Prime Contract, Duke Energy, through Duke Power Company (Duke Power), has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission

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Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of June 30, 2005, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. DPSG has recourse to the other owners of DCS for any amounts paid under the Duke Power Guarantee in excess of its proportional ownership percentage of DCS. Even though the Duke Power Guarantee does not provide for a specific limitation on a guarantor’s guarantee obligations, it does provide that any liability of such guarantor under the Duke Power Guarantee is directly related to and limited by the terms and conditions in the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Duke Power Subcontract. Duke Capital is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the Duke Power Guarantee due to the uncertainty of whether:

• DCS will exercise its options under the Duke Power Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract, which, in turn, will depend on whether the U.S. Congress will authorize funding for DCS work under the Prime Contract, and

• The parties to the Prime Contract and the Duke Power Subcontract, respectively, will reach agreement on the remaining open terms for each option phase under the contracts, and if so, what the terms and conditions might be.

Duke Capital has not recorded on its Consolidated Balance Sheets any liability for the potential exposure under the Duke Power Guarantee per FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” because DPSG and Duke Power are under common control.

Other Guarantees and Indemnifications.Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of June 30, 2005 was approximately $2.2 billion. Of this amount, approximately $1.4 billion relates to guarantees of payments and performance of affiliated entities such as Duke Energy Merchants (DEM) and approximately $400 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $150 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2007 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of June 30, 2005 was approximately $60 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of June 30, 2005 was approximately $500 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities. Of those letters of credit, approximately $225 million expire in 2005, with the remainder expiring in 2006.

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Notes To Consolidated Financial Statements—(Continued)

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of June 30, 2005, Duke Capital had guaranteed approximately $15 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2005 and 2006. Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of June 30, 2005, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly-owned entities. Of those guarantees, approximately $5 million expire in 2005, with the remainder expiring in 2006 and 2007.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Capital but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Capital has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Capital for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Capital also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Capital granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Capital has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2005 to 2019, with others having no specific term. Duke Capital is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

In connection with Duke Capital’s sale of the Murray merchant generation facility to KGen, in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by the bank to Georgia Power Company. The letter of credit, which expires in 2005, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Capital will operate the sold Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Capital for any payments Duke Capital makes with respect to the $120 million letter of credit.

Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s maximum potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Capital is unable to estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of June 30, 2005, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

16. New Accounting Standards

The following new accounting standards were adopted by Duke Capital subsequent to June 30, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

FASB Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In May 2004, the FASB staff issued FSP No. FAS 106-2, which superseded FSP No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of

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Notes To Consolidated Financial Statements—(Continued)

2003.” FSP FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP No. FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Post-retirement Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. The after-tax effect on net periodic post-retirement benefit cost was not material to 2004 or 2005.

EITF Issue No. 03-1,“The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” In March 2004, the EITF reached a consensus on Issue No. 03-1, which provides guidance on assessing whether impairments are other-than-temporary for marketable debt and equity securities accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”, and non-marketable equity securities accounted for under the cost method. The consensus also requires certain disclosures about unrealized losses that have not been recognized in earnings as other-than-temporary impairments. The disclosure provisions were effective for all periods ending after December 15, 2003. The other-than-temporary impairment application guidance was to be effective for reporting periods beginning after June 15, 2004.

In September 2004, the FASB issued FSP No. EITF Issue 03- 1- 1, Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”, which delays indefinitely the application of certain provisions of EITF Issue No. 03-1 until further guidance can be considered by the FASB. However, the FSP did not delay the effective date for the disclosure provisions of EITF Issue No. 03-1. Duke Capital continues to monitor this issue; however, based upon developments to date Duke Capital does not expect the final guidance to have a material impact on its consolidated results of operations, financial position or cash flows.

EITF Issue No. 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 of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 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 No. 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 Issue No. 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 in EITF Issue No. 03-13 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 in EITF Issue No. 03-13 was effective for Duke Capital beginning January 1, 2005. The impact to Duke Capital of adopting EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Capital does not currently expect EITF Issue No. 03-13 will have a material impact on its consolidated results of operations, cash flows or financial position.

The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of June 30, 2005:

SFAS No. 123 (Revised 2004), “Share-Based Payment”. In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes APB Opinion 25. SFAS No. 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. Timing for implementation of SFAS No. 123R, as amended in April 2005 by the SEC, is no later than the beginning of the first annual period beginning after June 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. Under SFAS No. 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amor - -

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Notes To Consolidated Financial Statements—(Continued)

tization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive method would record compensation expense for all unvested awards beginning in the first period restated.

Duke Energy currently has retirement eligible employees with outstanding share-based payment awards. Compensation cost related to those awards is currently recognized over the stated vesting period or until actual retirement occurs. Upon adoption of SFAS No. 123R, Duke Capital will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Capital does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Capital in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment”. On March 29, 2005, the SEC staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy is currently in the process of implementing SFAS No. 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 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 No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. SFAS No. 153 does not apply to transfers of nonmonetary assets between entities under common control. The impact to Duke Capital of adopting SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Capital does not currently expect adoption of SFAS No. 153 will have a material impact on its consolidated results of operations, cash flows or financial position.

FASB Interpretation (FIN) No. 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 No. 143, “Accounting for Asset Retirement Obligations.” 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 required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 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. Duke Capital is currently evaluating the impact of adopting FIN 47 as well as the interim transition provisions and cannot currently estimate the impact of FIN 47 on its consolidated results of operations, cash flows or financial position.

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DUKE CAPITAL LLC

Notes To Consolidated Financial Statements—(Continued)

17. Income Tax Expense

On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owned merchant generation facilities being owned by a newly created entity, Duke Energy Americas LLC (DEA), a directly wholly owned subsidiary of Duke Capital. DEA and Duke Capital are pass-through entities for U.S. income tax purposes. As a result of Duke Energy realigning these subsidiaries, approximately $50 million and $135 million of tax benefits for the three and six months ended June 30, 2005, respectively, relating to the tax losses from DEA and Duke Capital were not recognized by Duke Capital.

On October 22, 2004, the President of the United States signed the American Jobs Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 to 2010.

Under the guidance in FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Capital, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. In the first six months of 2005, Duke Capital recognized a benefit of approximately $1 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on the decision, Duke Energy plans to repatriate approximately $500 million in extraordinary dividends in 2005, as defined in the Act, and accordingly Duke Energy recorded a corresponding tax liability of $45 million as of December 31, 2004. During the second quarter 2005, Duke Energy reorganized various entities which enabled Duke Energy to reduce the $45 million tax liability to $41 million. This reorganization caused Duke Capital to record an additional income tax expense relating to the repatriation as the tax effects of the repatriation will be recognized at Duke Capital. This reorganization increased Duke Capital’s liability for the repatriation from $5 million at December 31, 2004 to $41 million at June 30, 2005. No extraordinary dividends were repatriated during the six months ended June 30, 2005. Duke Capital repatriated approximately $200 million of extraordinary dividends in July 2005.

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes have been made for potential liabilities resulting from these matters. As of June 30, 2005, Duke Capital had total provisions of approximately $120 million for uncertain tax positions, as compared to $125 million as of December 31, 2004, including interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

18. Subsequent Events

The Energy Policy Act of 2005 became law in August 2005 and addresses a wide span of issues. The legislation directs specified agencies to conduct a significant number of studies on various sectors of the energy industry. In addition, many of the provisions will require these agencies to develop rules and procedures for their application. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA), establishes a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear plants, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission, improves the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. The enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 7.

For information on subsequent events related to debt and credit facilities, acquisitions and dispositions, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and income taxes, see Notes 4, 7, 10, 13, 14 and 17.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.

Overview of Business Strategy and Economic Factors

Duke Capital LLC’s (Duke Capital’s) business strategy is to develop integrated energy businesses in targeted regions where Duke Capital’s capabilities in developing energy assets; operating power plants, natural gas liquid (NGL) plants and natural gas pipelines; optimizing commercial operations (including its affiliated real estate operation); and managing risk can provide comprehensive energy solutions for customers and create value for its parent company. For an in-depth discussion of Duke Capital’s business strategy and economic factors, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004.

RESULTS OF OPERATIONS

Results of Operations and Variances

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005		2004			Increase (Decrease)
	(in millions)
Operating revenues	$	4,314		$	3,851		$	463		$	8,705	$	7,928		$	777
Operating expenses		3,777			3,355			422			7,774		7,088			686
Gains on sales of investments in commercial and multi-family real estate		12			62			(50	)		54		121			(67	)
(Losses) gains on sales of other assets, net		—			(13	)		13			32		(365	)		397
Operating income		549			545			4			1,017		596			421
Other income and expenses, net		89			92			(3	)		1,394		138			1,256
Interest expense		223			262			(39	)		446		535			(89	)
Minority interest expense		77			43			34			493		81			412
Earnings from continuing operations before income taxes		338			332			6			1,472		118			1,354
Income tax expense from continuing operations		209			80			129			694		17			677
Income from continuing operations		129			252			(123	)		778		101			677
(Loss) income from discontinued operations, net of tax		(1	)		25			(26	)		1		272			(271	)
Net income	$	128		$	277		$	(149	)	$	779	$	373		$	406

Overview of Drivers and Variances

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated net income for the three months ended June 30, 2005, decreased $149 million, compared to the same period in 2004. Significant items that contributed to the decrease included:

• A $129 million increase in income tax expense from continuing operations, resulting primarily from tax losses from Duke Energy Americas LLC (DEA) not being recognized at Duke Capital in 2005, as well as the release of various income tax reserves in the second quarter 2004 totaling approximately $45 million and the recording of an additional $36 million expense for the repatriation of foreign earnings in 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”)

• A $109 million pre-tax gain (net of minority interest of $5 million) recorded in 2004 related to the settlement of the Enron bankruptcy proceedings

• A $45 million pre-tax gain at Crescent Resources LLC (Crescent) in the second quarter 2004 on the sale of the Alexandria tract in the Washington D.C. area

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• A $26 million after-tax decrease from discontinued operations driven primarily by a $40 million after-tax gain recorded in the second quarter 2004 related to the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business), partially offset by a $9 million after-tax charge on its European gas trading and marketing business (the European Business), and

• A $24 million pre-tax charge to increase liabilities associated with mutual insurance companies recorded in the second quarter 2005.

Partially offsetting these amounts were:

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• An approximate $70 million pre-tax increase in earnings (net of minority interest of $25 million) at Field Services due primarily to the favorable effects of commodity prices, net of hedging, excluding the impact of those hedges which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of Duke Energy Field Services, LLC (DEFS) by Duke Capital, and

• A $39 million pre-tax decrease in interest expense, due primarily to Duke Capital’s debt reduction efforts in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated net income for the six months ended June 30, 2005, increased $406 million, compared to the same period in 2004. Significant items that contributed to the improved results included:

• An $802 million pre-tax gain (net of minority interest of $343 million) recorded in 2005 on the sale of DEFS’s wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, L.P. (TEPPCO LP), an equity method investment of DEFS

• An approximate $360 million pre-tax charge in 2004 associated with the sale of Duke Energy North America’s (DENA) eight natural gas-fired merchant power plants: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi) in the southeastern United States (U.S.); and certain other power and gas contracts (collectively, the Southeast Plants)

• An approximate $120 million pre-tax increase in earnings (net of minority interest of $50 million) at Field Services due primarily to the favorable effects of commodity prices, net of hedging, excluding the impact of those hedges which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Capital

• An approximate $120 million pre-tax increase in earnings (net of minority interest of $15 million) at DENA primarily due to lower operating and general and administrative expenses, and the absence of mark-to-market losses associated with the disqualified hedge positions in 2004, partially offset by lower power generation sales as a result of milder weather in the western U.S. region and lower margins resulting from current weakness in the natural gas transportation and marketing business

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• An approximate $100 million pre-tax gain recorded in the first quarter 2005 on the sale of Duke Capital’s limited partner interest in TEPPCO LP

• A $89 million pre-tax decrease in interest expense, due primarily to Duke Capital’s debt reduction efforts in 2004

• An approximate $60 million pre-tax increase in earnings (net of minority interest of $1 million) at International Energy due primarily to the higher volumes and favorable foreign currency exchange rate changes in Brazil and higher product margins at National Methanol Company, and

• An approximate $21 million pre-tax gain recorded in the first quarter 2005 on the sale of DENA’s partially completed Grays Harbor power plant (Grays Harbor) in Washington state.

Partially offsetting these amounts were:

• A $677 million increase in income tax expense from continuing operations, resulting primarily from higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, as discussed above, tax losses from DEA not being recognized at Duke Capital in 2005, as well as the release of various income tax reserves in the second quarter 2004 totaling approximately $45 million and the recording of an additional $36 million expense for the repatriation of foreign earnings in 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”)

• A $271 million after-tax decrease in income from discontinued operations driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business, partially offset by a $9 million after-tax charge on its European Business

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• An approximate $250 million of realized and unrealized pre-tax losses recognized in 2005 on certain derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Capital (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”)

• A $109 million pre-tax gain (net of minority interest of $5 million) recorded in 2004 related to the settlement of the Enron bankruptcy proceedings

• A $45 million pre-tax gain at Crescent in the second quarter 2004 on the sale of the Alexandria tract in the Washington D.C. area, and

• A $24 million pre-tax charge to increase liabilities associated with mutual insurance companies recorded in the second quarter 2005.

On a consolidated and a segment reporting basis, results of operations through June 30, 2005, may not be indicative of the full year.

Consolidated Operating Revenues

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating revenues for the three months ended June 30, 2005 increased $463 million, compared to the same period in 2004. This change was driven primarily by:

• A $547 million increase at Field Services due primarily to higher average commodity prices, primarily NGL and natural gas, in the second quarter 2005

• A $61 million increase at Natural Gas Transmission due primarily to favorable foreign exchange rates as a result of the strengthening Canadian dollar and higher natural gas prices that are passed through to customers (mostly offset by gas price and currency impacts to expenses), and

• An approximate $45 million increase due principally to higher energy prices and volumes at International Energy and higher residential developed lot sales at Crescent.

Partially offsetting these increases in revenues were:

• A $94 million decrease in natural gas sales revenues at DENA due primarily to lower natural gas sales volumes as a result of the continued wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Capital’s 60/40 joint venture with ExxonMobil Corporation) operations, partially offset by higher average natural gas prices in the second quarter 2005

• A $77 million decrease at DENA due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, and

• A $22 million decrease in DENA’s net trading margin due primarily to the absence of mark-to-market gains associated with the disqualified hedge positions in the second quarter 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating revenues for the six months ended June 30, 2005 increased $777 million, compared to the same period in 2004. This change was driven primarily by:

• A $868 million increase at Field Services due primarily to higher average commodity prices, primarily NGL and natural gas, in 2005

• A $198 million increase at Natural Gas Transmission due primarily to higher natural gas prices that are passed through to customers and favorable foreign exchange rates as a result of the strengthening Canadian dollar (mostly offset by gas price and currency impacts to expenses)

• A $68 million increase in DENA’s net trading margin due primarily to the absence of mark-to-market losses associated with the disqualified hedge positions in 2004

• A $49 million increase at International Energy due primarily to higher energy prices and volumes, and

• A $37 million increase at Crescent due primarily to higher residential developed lot sales.

Partially offsetting these increases in revenues were:

• A $296 million decrease in natural gas sales revenues at DENA due primarily to lower natural gas sales volumes as a result of the continued wind-down of DETM operations, partially offset by higher average natural gas prices in 2005

• An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”), and

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• A $123 million decrease at DENA due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather.

For a more detailed discussion of operating revenues, see the segment discussions that follow.

Consolidated Operating Expenses

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating expenses for the three months ended June 30, 2005 increased $422 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $500 million increase in operating expenses at Field Services and Natural Gas Transmission driven primarily by higher average NGL and natural gas prices, and foreign exchange impacts

• A $114 million pre-tax gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings, and

• A $24 million pre-tax charge to increase liabilities associated with mutual insurance companies recorded in the second quarter 2005.

Partially offsetting these increases in expenses were:

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• An $87 million decrease in plant fuel costs and operations, maintenance and depreciation expenses at DENA due primarily to the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather, and

• A $56 million reduction in natural gas purchases at DENA due primarily to the continued wind-down of DETM, partially offset by higher average natural gas prices in 2005.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating expenses for the six months ended June 30, 2005 increased $686 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $900 million increase in operating expenses at Field Services and Natural Gas Transmission driven primarily by higher average NGL and natural gas prices, and foreign exchange impacts

• An approximate $120 million increase related to the recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”)

• A $114 million pre-tax gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings, and

• A $24 million pre-tax charge to increase liabilities associated with mutual insurance companies recorded in the second quarter of 2005.

Partially offsetting these increases in expenses were:

• A $249 million reduction in natural gas purchases at DENA due primarily to the continued wind-down of DETM, partially offset by higher average natural gas prices in 2005

• A $195 million decrease in plant fuel costs and operations, maintenance and depreciation expenses at DENA due primarily to the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather, and

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement.

For a more detailed discussion of operating expenses, see the segment discussions that follow.

Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated gains on sales of investments in commercial and multi-family real estate for the three months ended June 30, 2005 decreased $50 million, compared to the same period in 2004 primarily as a result of the 2004 gain on sale of the Alexandria tract in the Washington, DC area.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated gains on sales of investments in commercial and multi-family real estate for the six months ended June 30, 2005 decreased $67 million, compared to the same period in 2004 primarily as a result of the 2004 gain on sale of the Alexandria tract and a commercial project in the Washington, DC area.

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Consolidated (Losses) Gains on Sales of Other Assets, Net

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated (losses) gains on sales of other assets, net for the three months ended June 30, 2005 increased $13 million, compared to the same period in 2004. The increase was due primarily to 2004 pre-tax losses at DENA related to the liquidation of contractual positions in connection with the continued wind down of DETM’s operations.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated (losses) gains on sales of other assets, net for the six months ended June 30, 2005 increased $397 million, compared to the same period in 2004. The increase was due primarily to the charge in the first quarter 2004 associated with the sale of DENA’s Southeast Plants and the first quarter 2005 gain on the sale of DENA’s Grays Harbor power plant in Washington state.

Consolidated Operating Income

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating income for the three months ended June 30, 2005 was relatively flat, compared to the same period in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated operating income for the six months ended June 30, 2005 increased $421 million, compared to the same period in 2004. Increased operating income was due primarily to a loss in 2004 related to the sale of DENA’s Southeast Plants, a charge in 2004 related to the California and western U.S. energy markets settlement, favorable results at Field Services in 2005 driven primarily by favorable effects of commodity prices, net of hedging, favorable results at DENA in 2005 due primarily to higher net trading margins and lower operating expenses, mainly resulting from the sale of the Southeast Plant, and favorable results at International Energy in 2005 driven primarily by higher volumes and favorable foreign currency exchange rate changes, partially offset by charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, the gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings and the gain on sale of the Alexandria tract in the Washington D.C. area in the second quarter 2004.

Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses, net

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated other income and expenses, net for the three months ended June 30, 2005 was relatively flat, compared to the same period in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated other income and expenses, net for the six months ended June 30, 2005 increased approximately $1.3 billion, compared to the same period in 2004. The increase was due primarily to the gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP.

Consolidated Interest Expense

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated interest expense for the three months ended June 30, 2005 decreased $39 million, compared to the same period in 2004. This decrease was due primarily to Duke Capital’s debt reduction efforts in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated interest expense for the six months ended June 30, 2005 decreased $89 million, compared to the same period in 2004. This decrease was due primarily to Duke Capital’s debt reduction efforts in 2004.

Consolidated Minority Interest Expense

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated minority interest expense for the three months ended June 30, 2005 increased $34 million, compared to the same period in 2004 driven primarily by increased earnings from DEFS as a result of higher commodity prices.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated minority interest expense for the six months ended June 30, 2005 increased $412 million, compared to the same period in 2004 driven primarily by increased earnings at DEFS as a result of the sale of TEPPCO GP and higher commodity prices.

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PART I

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated income tax expense from continuing operations for the three months ended June 30, 2005 increased $129 million, compared to the same period in 2004. The increase primarily resulted from tax losses from DEA not being recognized at Duke Capital in 2005, as well as the release of various income tax reserves in the second quarter 2004, and the recording of an additional expense for the repatriation of foreign earnings for 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”).

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated income tax expense from continuing operations for the six months ended June 30, 2005 increased $677 million, compared to the same period in 2004. The increase primarily resulted from higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, tax losses from DEA not being recognized at Duke Capital in 2005, as well as the release of various income tax reserves in the second quarter 2004, and the recording of additional expense for the repatriation of foreign earnings for 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”).

Consolidated (Loss) Income from Discontinued Operations, net of tax

Three Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated (loss) income from discontinued operations, net of tax for the three months ended June 30, 2005 decreased $26 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business, offset by an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business.

Six Months Ended June 30, 2005 as Compared to June 30, 2004.Consolidated (loss) income from discontinued operations, net of tax for the six months ended June 30, 2005 decreased $271 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in 2004 related to the sale of the Asia-Pacific Business, offset by an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business.

Segment Results

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Capital, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Capital’s ownership interest in operations without regard to financing methods or capital structures.

Duke Capital’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Natural Gas Transmission	$	302		$	311		$	709		$	709
Field Services		166			95			1,087			186
DENA		(56	)		(38	)		(91	)		(595	)
International Energy		86			68			154			97
Crescent		39			87			91			147
Total reportable segment EBIT		537			523			1,950			544
Other		(12	)		30			(93	)		57
Interest expense		(223	)		(262	)		(446	)		(535	)
Interest income and other (a)		36			41			61			52
Consolidated earnings from continuing operations before income taxes	$	338		$	332		$	1,472		$	118

(a) Other includes foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

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The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

Natural Gas Transmission

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	749	$	688	$	61		$	1,924	$	1,726	$	198
Operating expenses		457		397		60			1,233		1,035		198
Gains on sales of other assets, net		2		9		(7	)		4		9		(5	)
Operating income		294		300		(6	)		695		700		(5	)
Other income, net of expenses		14		13		1			28		19		9
Minority interest expense		6		2		4			14		10		4
EBIT	$	302	$	311	$	(9	)	$	709	$	709	$	—
Proportional throughput, TBtu (a)		719		726		(7	)		1,775		1,815		(40	)

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations, since revenues are primarily composed of demand charges.

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $36 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• An $8 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas Limited (Union Gas). This revenue increase is offset in expenses, and

• A $4 million increase from completed and operational pipeline expansion projects in the United States.

Operating Expenses.The increase was driven primarily by:

• A $27 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

• A $17 million increase related to the 2004 resolution of ad valorem tax issues in various states, and

• An $8 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

EBIT. The decrease in EBIT was due primarily to the 2004 resolution of ad valorem tax issues, partially offset by earnings from expansion projects and favorable foreign exchange rate changes from the strengthening Canadian currency.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $105 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a markup at Union Gas. This revenue increase is offset in expenses

• A $93 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $10 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• An $8 million decrease at Union Gas primarily resulting from a new earnings-sharing mechanism effective January 1, 2005 (see Note 13 to the Consolidated Financial Statements, “Regulatory Matters”).

Operating Expenses.The increase was driven primarily by:

• A $105 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $71 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above), and

• A $17 million increase related to the 2004 resolution of ad valorem tax issues in various states.

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PART I

Other Income, net of expenses.The increase was driven primarily by a $5 million construction fee received from an affiliate related to the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream) Phase II project, 50% owned by Duke Capital, which went into service in February 2005.

EBIT. EBIT remained constant driven by increased earnings from expansion projects and favorable foreign exchange rate changes from the strengthening Canadian dollar offset by lower revenues at Union Gas due to the new earnings-sharing mechanism and the 2004 resolution of ad valorem tax issues.

Field Services

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,888	$	2,341	$	547		$	5,562	$	4,694	$	868
Operating expenses		2,651		2,209		442			5,237		4,437		800
Gains on sales of other assets, net		—		—		—			2		—		2
Operating income		237		132		105			327		257		70
Other income, net of expenses		7		15		(8	)		1,258		33		1,225
Minority interest expense		78		52		26			498		104		394
EBIT	$	166	$	95	$	71		$	1,087	$	186	$	901
Natural gas gathered and processed/transported, TBtu/d (a)		7.3		7.4		(0.1	)		7.2		7.3		(0.1	)
NGL production, MBbl/d (b)		370		368		2			367		360		7
Average natural gas price per MMBtu (c), (d), (e)	$	6.73	$	5.99	$	0.74		$	6.50	$	5.84	$	0.66
Average NGL price per gallon (d), (e)	$	0.75	$	0.61	$	0.14		$	0.74	$	0.60	$	0.14

(a) Trillion British thermal units per day

(b) Thousand barrels per day

(c) Million British thermal units

(d) Index-based market price

(e) Does not reflect results of commodity hedges.

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $250 million increase due to a $0.14 per gallon increase in average NGL prices

• A $210 million increase due to a $0.74 per MMBtu increase in average natural gas prices

• A $34 million increase attributable to the impact of cash flow hedging, which reduced revenues by approximately $14 million for the three months ended June 30, 2005 and by approximately $48 million for the same period in 2004. As a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, approximately $20 million of mark-to-market losses on these hedges for the three months ended June 30, 2005 have been presented in Other, as discussed below

• A $25 million increase attributable to higher natural gas sales volumes, partially offset by lower NGL sales volumes

• A $20 million increase attributable to a $14.85 per-barrel increase in average crude oil prices to $53.17 during the three months ended June 30, 2005 from $38.32 during the same period in 2004, and

• A $10 million increase in wholesale propane marketing activity primarily due to higher propane prices.

Operating Expenses. The increase was due primarily to:

• A $395 million increase due to higher average costs of raw natural gas supply due primarily to an increase in average NGL and natural gas prices

• A $20 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds, and for outside consulting fees

• A $15 million increase attributable to higher purchased raw natural gas supply, and

• A $10 million increase in wholesale propane marketing activity primarily, due to higher propane prices.

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PART I

Other Income, net of expenses. The decrease was due primarily to:

• A $10 million decrease in earnings from equity method investments, primarily as a result of the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the sale of Duke Capital’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense.The increase was due primarily to increased earnings from DEFS.

EBIT. The increase was driven primarily by the favorable effects of commodity price increases.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was due primarily to:

• A $400 million increase due to a $0.14 per gallon increase in average NGL prices

• A $325 million increase due to a $0.66 per MMBtu increase in average natural gas prices

• A $53 million increase attributable to the impact of cash flow hedging, which reduced revenues by approximately $41 million for the six months ended June 30, 2005 and by approximately $94 million for the same period in 2004. As a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, approximately $130 million of mark-to-market losses on these hedges for the six months ended June 30, 2005 have been presented in Other, as discussed below

• A $45 million increase attributable to a $14.90 per-barrel increase in average crude oil prices to $51.64 during the six months ended June 30, 2005 from $36.74 during the same period in 2004

• A $25 million increase in wholesale propane marketing activity primarily due to higher propane prices

• A $10 million increase attributable to higher natural gas volumes, partially offset by lower NGL sales volumes, and

• An $8 million increase attributable to higher transportation, storage and processing fees, primarily due to higher fees from processing contracts.

Operating Expenses. The increase was due primarily to:

• A $605 million increase due to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices

• An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI during the first quarter 2005 as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”). After the discontinuance of these hedges, changes in their fair value will be recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from Field Services results

• A $35 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds and for outside consulting fees

• A $20 million increase in wholesale propane marketing activity primarily due to higher propane prices, and

• A $10 million increase attributable to higher purchased raw natural gas supply.

Other Income, net of expenses. The increase was due primarily to:

• An approximate $1.1 billion pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Capital’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by

• A $16 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense.The increase was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS due to commodity price increases. The overall increase was not proportionate to the increase in Field Services’ earnings during the six months ended June 30, 2005, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital level that are not included in DEFS’ results prior to the discontinuance of cash flow hedges during the first quarter of 2005, as discussed above.

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EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP and the favorable effects of commodity price increases. Also during the first three months of 2005, Duke Capital discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”). As a result of the discontinuance of hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the six months ended June 30, 2005.

Matters Impacting Future Field Services Results

In July 2005, Duke Energy Corporation (Duke Energy) caused a Duke Capital subsidiary to complete the previously announced agreement with ConocoPhillips, Duke Capital’s co-equity owner in DEFS, to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. The DEFS disposition transaction involves DEFS transferring its Canadian assets to Duke Capital’s Natural Gas Transmission business unit as well as Duke Capital receiving cash from ConocoPhillips. The DEFS disposition transaction is estimated to result in a pre-tax gain to Field Services of approximately $600 million. Duke Capital will deconsolidate its investment in DEFS in July 2005, subsequent to the closing of the DEFS disposition transaction. For further information, see Duke Capital’s Current Report on Form 8-K dated July 11, 2005 which contains pro-forma information regarding the impact of the DEFS disposition transaction as if it occurred on January 1, 2004 for purposes of the pro-forma statement of operations and March 31, 2005 for the pro-forma balance sheet. Future Field Services results are subject to volatility for factors such as commodity price changes.

DENA

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	463		$	646		$	(183	)	$	931		$	1,270		$	(339	)
Operating expenses		525			674			(149	)		1,063			1,515			(452	)
(Losses) Gains on sales of other assets, net		(1	)		(16	)		15			27			(368	)		395
Operating loss		(63	)		(44	)		(19	)		(105	)		(613	)		508
Other income (loss), net of expenses		3			—			3			4			(2	)		6
Minority interest benefit		(4	)		(6	)		2			(10	)		(20	)		10
EBIT	$	(56	)	$	(38	)	$	(18	)	$	(91	)	$	(595	)	$	504
Actual plant production, GWh (a)		3,939			5,422			(1,483	)		7,895			10,883			(2,988	)
Proportional megawatt capacity in operation (a)											9,890			15,465			(5,575	)

(a) Includes plant production from plants accounted for under the equity method

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $94 million decrease due primarily to a $144 million reduction from lower natural gas sales volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $50 million from higher average natural gas prices

• A $77 million decrease due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, and

• A $22 million decrease in net trading margin due primarily to the absence of mark-to-market gains associated with the disqualified hedge positions in 2004.

Operating Expenses. The decrease was driven primarily by:

• A $105 million decrease due to the absence of a 2004 charge related to the California and western U.S. energy markets settlement in June 2004

• A $65 million reduction in plant fuel costs, due primarily to lower volumes resulting from the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather. Also contributing to the decrease was a favorable impact from natural gas hedging activities

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PART I

• A $56 million decrease due primarily to a $141 million reduction from lower natural gas purchase volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $85 million from higher average natural gas prices

• A $22 million reduction in operations, maintenance and depreciation expenses, due primarily to the sales of the Southeast Plants and partially completed western U.S. plants in 2004

• A $15 million decrease in general and administrative expenses, due primarily to headcount reductions, lower fees related to letters of credit, and reserve reductions, partially offset by

• A $113 million ($108 million net of minority interest expense) increase due to the absence of a 2004 gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Losses on Sales of Other Assets, net. The increase was due primarily to 2004 pre-tax losses of $16 million ($10 million net of minority interest expense) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations.

Minority Interest Benefit.The decreased benefit was due primarily to reduced losses at DETM as a result of the continued wind-down of DETM operations.

EBIT. The decrease was due primarily to reduced power generation sales as a result of milder weather in the western U.S region, lower margins resulting from the current weakness in the natural gas transportation and marketing business, and the absence of prior year mark-to-market gains on disqualified hedge positions. These decreases were partially offset by lower operating and general and administrative expenses, and the absence of prior year losses on asset sales.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $296 million decrease due primarily to a $396 million reduction from lower natural gas sales volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $100 million from higher average natural gas prices

• A $123 million decrease due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, partially offset by

• A $68 million increase in net trading margin due primarily to the absence of mark-to-market losses associated with the disqualified hedge positions in 2004.

Operating Expenses. The decrease was driven primarily by:

• A $249 million decrease due primarily to a $401 million reduction from lower natural gas purchase volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by an increase of approximately $152 million from higher average natural gas prices

• A $140 million reduction in plant fuel costs, due primarily to lower volumes resulting from the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather. Also contributing to the decrease was a favorable impact from natural gas hedging activities

• A $105 million decrease due to the absence of a 2004 charge related to the California and western U.S. energy markets settlement in June 2004

• A $55 million reduction in operations, maintenance and depreciation expenses, due primarily to the sales of the Southeast Plants and partially completed western U.S. plants in 2004

• A $26 million decrease in general and administrative expenses, due primarily to headcount reductions, lower fees related to letters of credit, and reserve releases, partially offset by

• A $113 million ($108 million net of minority interest expense) increase due to the absence of a 2004 gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Gains (Losses) on Sales of Other Assets, net. The increase was due primarily to the absence of approximately $360 million in 2004 pre-tax losses associated with the sale of the Southeast Plants and $14 million ($8 million net of minority interest expense) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations. Also contributing to the increase was a pre-tax gain of approximately $21 million associated with the sale of the Grays Harbor power plant in Washington State in 2005 (see Note 7 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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PART I

Minority Interest Benefit.The decrease was due primarily to reduced losses at DETM as a result of the continued wind-down of DETM operations.

EBIT. The increase was due primarily to the gains on asset sales in 2005, the absence of 2004 losses associated with the Southeast Plants, higher net trading margins and lower operating and general and administrative expenses. These increases were partially offset by lower margins resulting from the current weakness in the natural gas transportation and marketing business and reduced power generation sales as a result of milder weather in the western U.S. region.

Matters Impacting Future DENA Results

Duke Capital believes merchant energy will play a vital role in meeting the United States’ energy demand. One of Duke Capital’s stated objectives for 2005 is to position DENA to be a successful merchant operator. On May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they have entered into a definitive merger agreement, which contemplates that DENA will transfer its five midwest generation assets, with total property, plant and equipment balances of approximately $1.7 billion and net assets of approximately $1.5 billion as of June 30, 2005, to Cincinnati, Gas & Electric Company, a wholly-owned subsidiary of Cinergy. This transfer is not expected to have a material impact on DENA’s future results of operations (see Note 7 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Duke Capital also continues to pursue other options to further strengthen DENA’s business model. Depending on the options selected, there is a risk that material impairments or other charges or credits could be recorded, including the potential disqualification of certain contracts as hedges and the recognition of an approximate $1.4 billion unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption as of June 30, 2005. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power, and is partially offset by unrealized net gains on natural gas and power cash flow hedge positions of approximately $1.2 billion as of June 30, 2005. These amounts exclude obligations attributable to DENA’s gas transportation and structured power portfolio. (For further information, see Item 7 “Contractual Obligations” disclosure in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004). The timing of recognition of any loss on the normal purchases and normal sales contracts and the recognition of any unrealized net gains on DENA cash flow hedge positions may or may not occur in the same period, depending upon the options selected.

For 2005, DENA expects to significantly reduce its EBIT loss through additional cost savings and higher gross margins. DENA’s marketing efforts in 2005 will focus on contracting capacity and energy production from its plants. DENA’s future results of operations may not realize the full impact of commodity market price changes as certain of DENA’s future generation sales volumes and fuel purchases are contracted under fixed price arrangements.

International Energy

	Three Months Ended June 30,						Six Months Ended June 30,
	2005		2004		Increase (Decrease)		2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	182	$	147	$	35	$	350	$	301	$	49
Operating expenses		127		98		29		246		229		17
Operating income		55		49		6		104		72		32
Other income, net of expenses		34		22		12		55		31		24
Minority interest expense		3		3		—		5		6		(1	)
EBIT	$	86	$	68	$	18	$	154	$	97	$	57
Sales, GWh		4,527		4,247		280		9,062		8,811		251
Proportional megawatt capacity in operation								4,139		4,130		9

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $13 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $7 million increase in Guatemala mainly due to higher energy prices

• A $6 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices, and

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• A $5 million increase in Argentina primarily due to higher volumes and higher prices.

Operating Expenses.The increase was driven primarily by:

• A $12 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• An $11 million increase in Guatemala mainly due to higher fuel prices, maintenance expense and a bad debt reversal in 2004, and

• An $8 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes.

Other Income, net of expenses. The increase was driven primarily by a $9 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $14 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $10 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices

• A $10 million increase in Guatemala mainly due to higher energy prices, and

• A $7 million increase in Argentina due primarily to higher volumes and higher prices.

Operating Expenses.The increase was driven primarily by:

• A $14 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• A $13 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes, partially offset by

• A $13 million decrease related to a 2004 charge for the planned disposition of the ownership share in Compania de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004.

Other Income, net of expenses. The increase was driven primarily by a $16 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador and a $13 million charge associated with the planned disposition of the ownership share in Cantarell recorded in 2004.

Crescent

	Three Months Ended June 30,								Six Months Ended June 30,
	2005			2004		Increase (Decrease)			2005			2004		Increase (Decrease)
	(in millions)
Operating revenues	$	112		$	101	$	11		$	176		$	139	$	37
Operating expenses		79			75		4			130			111		19
Gains on sales of investments in commercial and multi-family real estate		12			62		(50	)		54			121		(67	)
Operating income		45			88		(43	)		100			149		(49	)
Other expense, net		(1	)		—		(1	)		(1	)		—		(1	)
Minority interest expense		5			1		4			8			2		6
EBIT	$	39		$	87	$	(48	)	$	91		$	147	$	(56	)

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was due primarily to a $14 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida offset by a $2 million decrease in residential club operations.

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Operating Expenses.The increase was due primarily to a $7 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $2 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate.The decrease was due primarily to a $49 million decrease in real estate land sales resulting from large land sales in 2004 ($45 million gain from the sale of the Alexandria tract in the Washington, D.C. area in June of 2004) as compared to minimal land sales in the second quarter of 2005.

EBIT. The decrease was due primarily to the reduction in real estate land sales as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by a $42 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida.

Operating Expenses.The increase was driven primarily by a $24 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $3 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by:

• A $49 million decrease in real estate land sales primarily due to the $45 million sale of the Alexandria tract in the Washington, D.C. area in June of 2004 as compared to minimal real estate land sales in the first half of 2005, and

• A $19 million decrease in commercial project sales due to the sale of a commercial project in the Washington, D.C. area in March of 2004 as compared to minimal project sales in the first half of 2005.

EBIT. The decrease was due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in the first half of 2004 as compared to minimal project and real estate land sales in the first half of 2005, partially offset by an increase in residential developed lot sales.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, D.C. area which resulted in higher than normal gains during 2004. Crescent expects segment EBIT from continuing operations and discontinued operations in 2005 to be at, or above segment EBIT from continuing operations and discontinued operations of approximately $250 million in 2004. When property management or other significant continuing involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

Other

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	28		$	37		$	(9	)	$	(38	)	$	79		$	(117	)
Operating expenses		46			11			35			65			41			24
Loss on sales of other assets, net		—			(7	)		7			—			(7	)		7
Operating (loss) income		(18	)		19			(37	)		(103	)		31			(134	)
Other income, net of expenses		6			11			(5	)		10			26			(16	)
EBIT	$	(12	)	$	30		$	(42	)	$	(93	)	$	57		$	(150	)

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by an approximate $20 million decrease as a result of the mark-to-market impact of certain cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were discontinued and transferred to Other (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”).

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Operating Expenses. The increase was driven primarily by a $24 million charge to increase liabilities associated with mutual insurance companies.

Loss on Sales of Other Assets, net.The increase was due primarily to a $7 million loss on the sale of an aircraft in 2004.

EBIT.The decrease was due primarily to the mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk and an increase in liabilities associated with mutual insurance companies, as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by an approximate $130 million decrease as a result of the mark-to-market impact of certain cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were discontinued and transferred to Other (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”).

Operating Expenses. The increase was driven primarily by a $24 million charge to increase liabilities associated with mutual insurance companies.

Loss on Sales of Other Assets, net.The increase was driven primarily by a $7 million loss on the sale of an aircraft in 2004.

Other Income, net of expenses.The decrease was driven primarily by a $17 million decrease in equity earnings from Duke/Fluor Daniel (D/FD) as a result of the wind-down of the partnership.

EBIT.The decrease was due primarily to the mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, an increase in liabilities associated with mutual insurance companies, and the decrease in equity earnings from D/FD, as discussed above.

Matters Impacting Future Other Results

Future Other results will be subject to volatility as a result of the changes in the mark-to-market of certain Field Services commodity price risk contracts subsequent to the discontinuance of hedge accounting in first quarter 2005. The fair value of these contracts as of June 30, 2005 was a liability of approximately $225 million, and approximately $120 million of this value is attributable to contracts which will settle in 2005. As these contracts settle Duke Capital will realize an offset to revenues at Field Services.

Other Impacts on Net Income

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $39 million, due primarily to Duke Capital’s debt reduction efforts in 2004.

Minority Interest Expense.Minority interest expense increased by $34 million driven primarily by increased earnings from DEFS, as a result of higher commodity prices.

Income Tax Expense from Continuing Operations.The effective tax rate for the three months ended June 30, 2005 was 62%, compared to 24% for the same period in 2004. The increase in the effective tax rate was due primarily to tax losses from DEA not being recognized at Duke Capital in 2005, the release of approximately $45 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004 and the recording of an additional $36 million expense for the repatriation of foreign earnings in 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”).

(Loss) Income from Discontinued Operations, net of tax.The $26 million decrease was driven primarily by a $40 million after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business. This gain was partially offset by a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 10 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $89 million, due primarily to Duke Capital’s debt reduction efforts in 2004.

Minority Interest Expense.Minority interest expense increased $412 million, driven primarily by increased earnings at DEFS, as a result of the sale of TEPPCO GP and higher commodity prices.

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Income Tax Expense from Continuing Operations.The effective tax rate for the six months ended June 30, 2005 was 47%, compared to 14% for same period in 2004. The increase in the effective tax rate was due primarily to tax losses from DEA not being recognized at Duke Capital in 2005, the release of approximately $45 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004, and the recording of an additional $36 million expense for the repatriation of foreign earnings in 2005 (see Note 17 to the Consolidated Financial Statements, “Income Tax Expense”). Additionally, the increase in income tax expense from continuing operations is a result of higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, as discussed above.

(Loss) Income from Discontinued Operations, net of tax. The $271 million decrease was driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business. This gain was partially offset by a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 10 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $755 million for the six months ended June 30, 2005, compared to the same period in 2004 due primarily to approximately $600 million of lower net income, excluding gains, losses, impairments and minority interest expense, in 2005 as compared to 2004. Additionally, approximately $130 million of additional collateral was posted by Duke Capital during 2005 primarily attributable to increases to forward market prices of power which was offset by approximately $50 million of additional collateral posted by Duke Capital in 2004.

Investing Cash Flows

Net cash provided by (used in) investing activities increased approximately $1.5 billion for the six months ended June 30, 2005 as compared to the same period in 2004. This increase was principally driven by the approximate $1.3 billion in proceeds on sales of equity investments and other assets in 2005, primarily due to the sale of TEPPCO GP and Duke Capital’s interest in TEPPCO LP for approximately $1.2 billion, offset by the approximate $700 million in proceeds received in 2004 primarily as a result of the sale of the Asia-Pacific Business, the sale of turbines and excess equipment, and the sale of Field Services’ assets. Additionally, approximately $100 million of the increase in investing activities is due to reduced capital and investment expenditures during 2005. Additionally, during 2004, an additional amount of cash of approximately $1 billion was invested in short-term investments as a result of the 2004 disposition transactions and increased operating cash flows, as discussed above, which resulted in excess cash balances being invested in these short-term investments.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased approximately $840 million for the six months ended June 30, 2005, compared to same period in 2004. This change was due primarily to approximately $720 million of net distributions to Duke Energy (to provide funding for the execution of Duke Energy’s accelerated share acquisition plan) and lower debt issuances in 2005 as compared to 2004. (For further discussion on the net distributions to Duke Energy, see Note 8 to the Consolidated Financial Statements, “Member’s Equity and Related Party Transactions.”)

Cash generated from operations, the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, and the DEFS disposition transaction are expected to be adequate for funding Duke Capital’s capital expenditures, planned debt reductions and distributions to Duke Energy in 2005.

During 2004, $267 million of cash advances were received by Duke Capital from Duke Energy. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Duke Capital classified the $267 million as an addition to Member’s Equity. This forgiveness is presented as a non-cash financing activity in the Consolidated Statements of Cash Flows for the six months ended June 30, 2005.

In April 2005, Duke Capital received a $269 million capital contribution from Duke Energy, which Duke Capital classified as an addition to Member’s Equity.

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Significant Financing Activities. In December 2004, Duke Capital reached an agreement to sell its Grays Harbor facility to an affiliate of Invenergy LLC. In 2004, Duke Capital terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Capital in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

Available Credit Facilities and Restrictive Debt Covenants.Duke Capital’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2005, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

Credit Ratings.The credit ratings of Duke Capital and its subsidiaries, with the exception of Maritimes & Northeast Pipeline LLC and Maritimes & Northeast LP, have not changed since March 1, 2005 as disclosed in “Management’s Discussion and Analysis of Results of Operations and Financial Condition – Liquidity and Capital Resources” in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004. The following table summarizes the August 5, 2005 credit ratings from the agencies retained by Duke Capital to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of August 5, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Capital LLC (a)	BBB-	Baa3	Not applicable
Duke Energy Field Services (a)	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP (a)	BBB	Baa2	Not applicable
Westcoast Energy Inc.	BBB	Not applicable	A(low)
Union Gas Limited (a)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC (b)	A	A2	A
Maritimes & Northeast Pipeline, LP (b)	A	A2	A
Duke Energy Trading and Marketing, LLC (c)	BBB-	Not applicable	Not applicable

(a) Represents senior unsecured credit rating

(b) Represents senior secured credit rating

(c) Represents corporate credit rating

In May 2005, following the announcement of Duke Energy’s merger with Cinergy, Standard & Poor’s Ratings Service placed the ratings of Duke Capital and its subsidiaries (excluding DEFS, Maritimes & Northeast Pipeline LLC and Maritimes & Northeast Pipeline LP) on “CreditWatch with negative implications.” In addition, Moody’s Investors Service revised the ratings outlook of Duke Capital and Texas Eastern Transmission LP to “Developing” and Dominion Bond Rating Service placed the credit ratings of Westcoast Energy Inc. “Under Review with Developing Implications.”

In August 2005, Moody’s Investors Service downgraded the credit rating of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP from A1 to A2. Moody’s actions were primarily a result of their concerns over downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. Moody’s concluded their action placing the ratings outlook for both companies to “stable”.

Duke Capital’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and balance distributions to Duke Energy, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Capital is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Capital’s credit ratings could be negatively impacted. In addition, the completion of Duke Energy’s merger with Cinergy and the resulting corporate structure could impact the credit ratings of Duke Capital or its subsidiaries.

Duke Capital and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Capital’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Capital’s collateral requirements. DENA conducts business throughout the United States and Canada through Duke

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Energy North America LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participates in DETM, which is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Capital.

A reduction in DETM’s credit rating to below investment grade as of June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $150 million. Additionally, as a result of DETM’s credit rating as of June 30, 2005, Duke Capital could be required to segregate up to approximately $260 million of cash collateral held by Duke Capital. Amounts above reflect Duke Capital’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $290 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate swap and foreign exchange agreements may require settlement payments due to termination of the agreements. As of June 30, 2005, Duke Capital could have been required to pay up to $10 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.

If credit ratings for Duke Capital or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to quantify fully in addition to the posting of additional collateral and segregation of cash described above.

Other Financing Matters.As of June 30, 2005, Duke Capital and its subsidiaries had effective Securities and Exchange Commission (SEC) shelf registrations for up to $592 million in gross proceeds from debt and other securities. The total amount available under effective shelf registrations decreased $500 million as compared to December 31, 2004, resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of June 30, 2005, Duke Capital had access to 900 million Canadian dollars (approximately U.S. $732 million) available under the Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 500 million Canadian dollars will expire in November 2005 and 400 million Canadian dollars will expire in July 2006.

Contractual Obligations and Commercial Commitments

Duke Capital enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the first six months of 2005, there were no material changes in Duke Capital’s contractual obligations and commercial commitments. For an in-depth discussion of Duke Capital’s contractual obligations and commercial commitments, see “Contractual Obligations and Commercial Commitments” and “Quantitative and Qualitative Disclosures about Market Risk” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Capital’s Annual Report on Form 10-K for the year-ended December 31, 2004.

OTHER ISSUES

Duke Energy Merger with Cinergy.On May 9, 2005, Duke Energy and Cinergy announced they have entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $4 billion. The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. (For further discussion of the status of regulatory filings see Note 13 to the Consolidated Financial Statements, “Regulatory Matters”.) The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions. Among other things, the merger agreement contemplates potential transactions that could involve the transfer of certain assets out of Duke Capital in connection with the merger. However, any potential transactions involving assets of Duke Capital and related consideration remain subject to change.

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Although Duke Energy and Cinergy believe that the expectation as to timing for the closing of the merger described above is reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all required approvals will be received.

Further information concerning the structure and details of the proposed merger is set forth in Duke Energy’s Current Report on Form 8-K dated May 9, 2005, which includes as exhibits the merger agreement and a joint press release of Duke Energy and Cinergy announcing the execution of the merger agreement. In connection with the merger, a registration statement on Form S-4 has been filed with the SEC by Duke Energy Holding Corp. (Registration No. 333-126318), containing a preliminary joint proxy statement/prospectus.

Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Capital has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6% below their 1990 level over the period 2008 to 2012. The Canadian government’s strategy for achieving its Kyoto reduction target includes, among other things, a proposal for an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (LFE). Consultations to develop plan details for the LFE program are under way. A draft LFE rule could be issued in the fall of 2005 and finalized in the spring of 2006. If an LFE program is ultimately enacted, then all of Duke Capital’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of carbon dioxide (CO₂) emission credits to actual emission reductions at the source, or a combination of strategies.

In 2001, President George W. Bush declared that the United States would not ratify the Kyoto Protocol. Instead, the U.S. greenhouse gas policy currently favors voluntary actions, continued research, and technology development over near-term mandatory greenhouse gas reduction requirements. Although several bills have been introduced in Congress that would compel CO₂ emission reductions, none has advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO₂ emission reduction program being enacted in the near future, or the specific requirements of any such regime, is highly uncertain. Some states are contemplating or have taken steps to manage greenhouse gas emissions, and while a number of U.S. states in the Northeast and far West are discussing the possibility of enacting either state-specific or regional programs in the future that would mandate reductions in greenhouse gas emissions, the outcome of those discussions is highly uncertain.

Duke Capital recently announced that it supports the enactment of U.S. federal legislation that would encourage a gradual transition to a lower-carbon-intensive economy, preferably in the form of a federal-level carbon tax that would apply to all sectors of the economy. Duke Capital believes that it is in the best interest of its investors and customers to actively participate in the evolution of federal policy on this important issue.

That Duke Capital will be proactive in climate change policy debate in the United States does not change the uncertainty around climate change policy. Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian policy, Duke Capital cannot estimate the potential effect of either nation’s greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Capital will assess and respond to the potential implications of greenhouse gas policies for its business operations in the United States and Canada if policies become sufficiently developed and certain to support a meaningful assessment.

(For additional information on other issues related to Duke Capital, see Note 13 to the Consolidated Financial Statements, “Regulatory Matters” and Note 14 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of June 30, 2005:

Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), “Share-Based Payment”. In December of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes Accounting Principles Board (APB) Opinion 25. SFAS No. 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. Timing for implementation of SFAS No. 123R, as amended in April 2005 by the SEC, is no later than the beginning of the first annual period beginning after June 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. Under SFAS No. 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive method would record compensation expense for all unvested awards beginning in the first period restated.

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Duke Energy currently has retirement eligible employees with outstanding share-based payment awards. Compensation cost related to those awards is currently recognized over the stated vesting period or until actual retirement occurs. Upon adoption of SFAS No. 123R, Duke Capital will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Capital does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Capital in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment”. On March 29, 2005, the SEC staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy is currently in the process of implementing SFAS No. 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 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 No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. SFAS No. 153 does not apply to transfers of nonmonetary assets between entities under common control. The impact to Duke Capital of adopting SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Capital does not currently expect adoption of SFAS No. 153 will have a material impact on its consolidated results of operations, cash flows or financial position.

FASB Interpretation (FIN) No. 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 No. 143, “Accounting for Asset Retirement Obligations.” 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 required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 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. Duke Capital is currently evaluating the impact of adopting FIN 47 as well as the interim transition provisions and cannot currently estimate the impact of FIN 47 on its consolidated results of operations, cash flows or financial position.

Subsequent Events

The Energy Policy Act of 2005 became law in August 2005 and addresses a wide span of issues. The legislation directs specified agencies to conduct a significant number of studies on various sectors of the energy industry. In addition, many of the provisions will require these agencies to develop rules and procedures for their application. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA), establishes a self-regulating electric reliability organization governed by an independent board with Federal Energy Regulatory Commission (FERC) oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear plants, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission, improves the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. The enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 7 to the Consolidated Financial Statements, “Acquisitions and Dispositions”.

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For information on subsequent events related to debt and credit facilities, acquisitions and dispositions, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and income taxes see Notes 4, 7, 10, 13, 14 and 17 to the Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

For an in-depth discussion of Duke Capital’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004.

Commodity Price Risk

Normal Purchases and Normal Sales. The unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption was approximately $1.4 billion as of June 30, 2005 and $900 million as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized net gains on natural gas and power cash flow hedge positions of approximately $1.2 billion as June 30, 2005 and $750 million as of December 31, 2004, which are recorded on the Consolidated Balance Sheets in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. A key objective for Duke Capital in 2005 is to position DENA to be a successful merchant operator. Duke Capital is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. Depending on the options selected, there is a risk that material impairments or other charges or credits could be recorded, including the potential disqualification of DENA’s power forward sales contracts designated under the normal purchases and normal sales exemption. This would result in the recognition of all unrealized losses associated with these forward contracts. These amounts exclude obligations attributable to DENA’s gas transportation and structured power portfolio. For further information, see Item 7 “Contractual Obligations” disclosure in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2004. The timing of recognition of any loss on the normal purchases and normal sales contracts and the recognition of any unrealized net gains on DENA cash flow hedge positions may or may not occur in the same period, depending upon the options selected.

Trading and Undesignated Contracts. The risk in the mark-to-market portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Capital’s DER amounts for commodity derivatives recorded using the mark-to-market model of accounting are shown in the following table.

Daily Earnings at Risk (in millions)

	June 30, 2005 One-Day Impact on Operating Income for 2005 (a)		Estimated Average One-Day Impact on Operating Income for Second Quarter 2005 (a)		Estimated Average One-Day Impact on Operating Income for the Year 2004 (a)		High One-Day Impact on Operating Income for Second Quarter 2005 (a)		Low One-Day Impact on Operating Income for Second Quarter 2005 (a)
Calculated DER	$	3	$	4	$	16	$	6	$	3

(a) DER measures the mark-to-market portfolio’s impact on earnings. While this calculation includes both trading and undesignated contracts, the trading portion, as defined by EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” is not material.

The DER figures above do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Capital’s interest in DEFS to ConocoPhillips (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”).

Credit Risk

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments due to IDC. In 2000, Duke Hidalgo was sold to Calpine Corporation and Duke Capital remained responsible for the lease guaranty obligations. Calpine Corporation has indemnified Duke Capital’s lease guaranty obligations. Total maximum exposure under this guarantee obligation as of June 30, 2005 is approximately $200 million.

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Item 4. Controls and Procedures.

Duke Capital’s management, including its President and Chief Financial Officer, have evaluated the effectiveness of Duke Capital’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. Duke Capital’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in Duke Capital’s reports under the Exchange Act are accumulated and communicated to management, including its President and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

Because of Duke Capital’s ongoing evaluation of internal controls over financial reporting, management continues to implement procedures and controls to enhance the reliability of Duke Capital’s internal control procedures including planned improvements in our financial closing and consolidation processes. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2005 that have materially affected, or are reasonably likely to materially affect, Duke Capital’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For information regarding legal proceedings that became reportable events or in which there were material developments in the second quarter of 2005, see Note 13 to the Consolidated Financial Statements, “Regulatory Matters” and Note 14 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Item 6. Exhibits.

    (a) Exhibits

Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.

Exhibit Number
2.1	Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of May 26, 2005 (filed in Form 10-Q of Duke Energy Corporation, August 9, 2005, File No. 1-4928, as Exhibit 10.4)
2.1.1	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 in Form 10-Q of Duke Energy Corporation, August 9, 2005, File No. 1-4928, as Exhibit 10.4.1)
2.1.2	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 in Form 10-Q of Duke Energy Corporation, August 9, 2005, File No. 1-4928, as Exhibit 10.4.2)
10.1	$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 in Form 10-Q of Duke Energy Corporation, August 9, 2005, File No. 1-4928, as Exhibit 10.2)
10.2	$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 in Form 10-Q of Duke Energy Corporation, August 9, 2005, File No. 1-4928, as Exhibit 10.3)
*31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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SIGNATURES

Pursuant to the requirements 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.

	DUKE CAPITAL LLC
Date: August 15, 2005	/S/    DAVID L. HAUSER
	David L. Hauser President
Date: August 15, 2005	/S/    STEVEN K. YOUNG
	Steven K. Young Chief Financial Officer and Controller

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