DUKE CAPITAL LLC - 10-Q Quarterly Report

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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, 2004

Commission File Number 0-23977

DUKE CAPITAL LLC

(Exact name of Registrant as Specified in its Charter)


Delaware		20-1107586
(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. Yes x 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 ¨ No x

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.

DUKE CAPITAL LLC

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2004

INDEX


Item			Page
	PART I. FINANCIAL INFORMATION

1.	Financial Statements		1
		Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003, as revised	1
		Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003	2
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003, as revised	4
		Notes to Consolidated Financial Statements	5
2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition		33
3.	Quantitative and Qualitative Disclosures about Market Risk		52
4.	Controls and Procedures		53

	PART II. OTHER INFORMATION

1.	Legal Proceedings		54
6.	Exhibits and Reports on Form 8-K		54
	Signatures		55

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

•

Lack of improvement or further 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 domestic and international power, pipeline, gathering, processing and other infrastructure projects

•

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 and

•

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

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.

Item 1.

Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions)


	Three Months Ended June 30,					Six Months Ended June 30,
	2004			2003		2004			2003
				(as Revised - See Note 1)					(as Revised - See Note 1)
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	3,259		$	3,186	$	6,408		$	6,781
Regulated natural gas		635			636		1,617			1,515

Total operating revenues		3,894			3,822		8,025			8,296

Operating Expenses
Natural gas and petroleum products purchased		2,345			2,410		5,075			5,409
Operation, maintenance and other		499			531		975			905
Depreciation and amortization		243			260		499			511
Fuel used in electric generation and purchased power		263			107		505			353
Property and other taxes		50			68		132			135

Total operating expenses		3,400			3,376		7,186			7,313

Gains on Sales of Investments in Commercial and Multi-Family Real Estate		62			9		121			11
(Losses) Gains on Sales of Other Assets, net		(13	)		1		(365	)		2

Operating Income		543			456		595			996

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		42			17		76			51
Gains on sales of equity investments		—			219		—			233
Other income and expenses, net		50			25		61			47

Total other income and expenses		92			261		137			331
Interest Expense		263			255		536			520
Minority Interest Expense		41			39		79			78

Earnings From Continuing Operations Before Income Taxes		331			423		117			729
Income Tax Expense		80			148		17			248

Income From Continuing Operations		251			275		100			481
Discontinued Operations
Net operating (loss) income, net of tax		(4	)		16		4			18
Net gain on dispositions, net of tax		30			11		269			11

Income From Discontinued Operations		26			27		273			29
Income Before Cumulative Effect of Change in Accounting Principle		277			302		373			510
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			—		—			(133	)

Net Income	$	277		$	302	$	373		$	377

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2004		December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	2,669	$	986
Receivables (net of allowance for doubtful accounts of $201 at June 30, 2004 and $236 at December 31, 2003)		2,387		2,482
Inventory		407		483
Assets held for sale		113		424
Unrealized gains on mark-to-market and hedging transactions		1,272		1,472
Other		537		467

Total current assets		7,385		6,314

Investments and Other Assets
Investments in unconsolidated affiliates		1,331		1,380
Goodwill		3,855		3,962
Notes receivable		244		260
Unrealized gains on mark-to-market and hedging transactions		1,604		1,815
Assets held for sale		692		1,444
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $28 at June 30, 2004 and $32 at December 31, 2003)		1,228		1,331
Other		855		1,336

Total investments and other assets		9,809		11,528

Property, Plant and Equipment
Cost		24,909		25,660
Less accumulated depreciation and amortization		4,929		4,457

Net property, plant and equipment		19,980		21,203

Regulatory Assets and Deferred Debits		1,083		1,060

Total Assets	$	38,257	$	40,105

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2004		December 31, 2003
LIABILITIES AND MEMBER’S/STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	1,858	$	2,018
Notes payable and commercial paper		41		52
Taxes accrued		378		—
Interest accrued		235		229
Liabilities associated with assets held for sale		44		651
Current maturities of long-term debt		1,276		1,192
Unrealized losses on mark-to-market and hedging transactions		1,070		1,185
Other		1,291		1,425

Total current liabilities		6,193		6,752

Long-term Debt, including debt to an affiliate of $258 at June 30, 2004 and December 31, 2003		13,257		13,652

Deferred Credits and Other Liabilities
Deferred income taxes		2,422		2,360
Unrealized losses on mark-to-market and hedging transactions		1,360		1,698
Liabilities associated with assets held for sale		—		737
Other		1,101		1,157

Total deferred credits and other liabilities		4,883		5,952

Commitments and Contingencies
Minority Interests		1,674		1,701

Member’s/Common Stockholder’s Equity
Common stock, no par, 3,000 shares authorized, 1,010 shares outstanding		—		—
Paid-in capital		—		8,564
Retained earnings		—		2,884
Member’s equity		11,818		—
Accumulated other comprehensive income		432		600

Total member’s/common stockholder’s equity		12,250		12,048

Total Liabilities and Member’s/Stockholder’s Equity	$	38,257	$	40,105

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Six Months Ended June 30,
	2004			2003
				(as Revised - See Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	373		$	377
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		507			541
Cumulative effect of change in accounting principle		—			133
Gains on sales of investments in commercial and multi-family real estate		(121	)		(11	)
Losses (gains) on sales of equity investments and other assets		78			(260	)
Deferred income taxes		(51	)		56
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		146			(103	)
Receivables		137			1,014
Inventory		76			(8	)
Other current assets		29			(127	)
Increase (decrease) in
Accounts payable		(248	)		(645	)
Taxes accrued		423			377
Other current liabilities		(29	)		(66	)
Capital expenditures for residential real estate		(138	)		(76	)
Cost of residential real estate sold		80			50
Other, assets		296			(186	)
Other, liabilities		57			39

Net cash provided by operating activities		1,615			1,105

CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net of refund		(533	)		(852	)
Net proceeds from the sale of equity investments and other assets, and sales of and collections on notes receivable		687			1,196
Proceeds from the sales of commercial and multi-family real estate		303			47
Other		(47	)		(10	)

Net cash provided by investing activities		410			381

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt		112			259
Payments for the redemption of
Long-term debt		(332	)		(827	)
Guaranteed preferred beneficial interests in subordinated notes		—			(250	)
Preferred stock of a subsidiary		(76	)		—
Notes payable and commercial paper		(21	)		(802	)
Distributions to minority interests		(703	)		(1,484	)
Contributions from minority interests		638			1,467
Capital contributions from parent		—			800
Dividends paid		(7	)		(7	)
Other		7			(4	)

Net cash used in financing activities		(382	)		(848	)

Changes in cash and cash equivalents associated with assets held for sale		40			—

Net increase in cash and cash equivalents		1,683			638
Cash and cash equivalents at beginning of period		986			814

Cash and cash equivalents at end of period	$	2,669		$	1,452

Supplemental Disclosures
Significant non-cash transactions:
Non-cash proceeds related to sale of Asia-Pacific operations	$	838		$	—
Proceeds from remarketing of Equity Units for senior notes	$	875		$	—

See Notes to Consolidated Financial Statements.

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. As a result, the Consolidated Balance Sheet for 2004 no longer reflects Paid-in Capital and Retained Earnings as those accounts are now characterized as Member’s Equity. 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 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, 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/A for the year ended December 31, 2003.

In 2003, Duke Energy Fuels (DE Fuels) merged into a wholly owned subsidiary of Duke Capital. Duke Capital accounted for and reported the merger at historical cost as of the beginning of the earliest period presented and all prior years presented in the Consolidated Financial Statements were revised on a comparative basis. Therefore, net income, as previously reported in Duke Capital’s Quarterly Report on Form 10-Q for June 30, 2003, was increased by approximately $5 million, from $297 million to $302 million, for the three months and reduced by approximately $75 million, from $452 million to $377 million, for the six months ended June 30, 2003 as a result of the merger of DE Fuels into Duke Capital. For further information related to this merger see Duke Capital’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2003.

Use of Estimates. To conform with generally accepted accounting principles in the United States, management makes estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Income Tax Expense. The effective income tax rate was 24% for the three months and 15% for the six months ended June 30, 2004, compared to 35% for the three months and 34% for the six months ended June 30, 2003. The decreased rates were due primarily to the reversal of $45 million of state and federal income tax reserves. These reserves were released in the second quarter of 2004 due to the resolution of various income tax positions taken by Duke Capital and changes in estimates.

Reclassifications and Revisions. In 2004, Duke Capital elected to change its business segments to present Crescent Resources LLC (Crescent) as a separate segment. In connection with this change, management determined that revisions were required to reclassify certain financial statement line items related to Crescent’s activities. In Duke Capital’s Quarterly Report on Form 10-Q for June 30, 2003, the cash outflows related to Crescent’s purchases of

commercial, residential and multi-family real estate were presented as a component of capital expenditures within cash flows from investing activities. The proceeds from the sales of these properties, as well as proceeds from the sales of “legacy” land, were shown as part of the reconciliation of net income to net cash flows from operating activities, and thus included in cash flows from operating activities.

Duke Capital has since determined that the cash inflows and outflows from Crescent’s purchases and sales of commercial and multi-family properties, as well as the proceeds from the sales of “legacy” land, should be presented as a component of cash flows from investing activities. All cash inflows and outflows related to Crescent’s residential properties should be presented on a net basis within cash flows from operating activities, whereas in past presentations, only the inflows were presented within cash flows from operating activities. As a result of the change, net cash provided by operating activities decreased by $123 million from $1,228 million to $1,105 million and net cash provided by investing activities increased by $123 million from $258 million to $381 million in the June 30, 2003 Consolidated Statements of Cash Flows.

Also in Duke Capital’s Quarterly Report on Form 10-Q for June 30, 2003, all proceeds from sales of real estate by Crescent were reported in revenues and the cost basis for all properties sold was included in operation and maintenance expenses in the Consolidated Statements of Operations. Consistent with the change in presentation noted above for the Consolidated Statements of Cash Flows, Duke Capital has determined that amounts related to the purchases and sales of commercial and multi-family real estate, as well as the sales proceeds and underlying cost of “legacy” land, should be presented in the Consolidated Statements of Operations as Gains on Sales of Investments in Commercial and Multi-Family Real Estate of $9 million for the three months and $11 million for the six months ended June 30, 2003, rather than presented in revenues, and operation and maintenance expenses. As a result of this change, total operating revenues decreased by $38 million, from $3,860 million to $3,822 million, for the three months and $40 million, from $8,336 million to $8,296 million, for the six months ended June 30, 2003, and total operating expenses decreased by $29 million, from $3,405 million to $3,376 million, for the three months and $29 million, from $7,342 million to $7,313 million, for the six months ended June 30, 2003.

Also included in the reclassified amounts are increases to both Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, and to Natural Gas and Petroleum Products Purchased of $223 million for the three months and $459 million for the six months ended June 30, 2003, related to the Field Services segment.

Some prior period amounts have 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 Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and 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 for Duke Capital employees 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 (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income, as reported	$	277		$	302		$	373		$	377
Add: stock-based compensation expense included in reported net income, net of related tax effects		2			3			5			5
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(4	)		(7	)		(10	)		(14	)

Pro forma net income	$	275		$	298		$	368		$	368

3. Inventory

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


Inventory (in millions)

	June 30, 2004		December 31, 2003
Natural gas and natural gas liquid products held in storage for transmission, processing, and sales commitments	$	224	$	299
Materials and supplies		137		139
Petroleum products		46		45

Total inventory	$	407	$	483

4. Debt and Credit Facilities

In February 2004, Duke Capital remarketed $875 million of senior notes, due in 2006, underlying Duke Energy’s Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009, and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with Emerging Issues Task Force (EITF) Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the first quarter of 2004.

In April 2004, approximately $840 million of debt was retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific operations. This does not include approximately $50 million of Australian debt, which has been placed in trust and fully funded in connection with the closing of the sale transaction and will be repaid in September 2004. This trust is included in the Consolidated Financial Statements as Duke Capital is the primary beneficiary of the trust and, therefore, is required to consolidate the trust under provisions of FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” The Asia-Pacific debt was classified as Current and Non-Current Liabilities Associated with Assets Held for Sale on the December 31, 2003 Consolidated Balance Sheet. Duke Capital completed the sale of the Asia-Pacific assets, which includes substantially all of Duke Capital’s assets in Australia and New Zealand, to Alinta Ltd. on April 23, 2004.

In April 2004, Duke Capital purchased $101 million of its outstanding notes in the open market. These purchases included $49 million of Duke Capital 5.50% senior notes due March 1, 2014 and $52 million of Duke Capital 4.37% senior notes due March 1, 2009. The securities were redeemed at the then current market price plus accrued interest.

In July 2004, Duke Capital announced that on August 31, 2004, it will redeem the entire issue of Duke Capital Financing Trust III 8 3/8% Trust Preferred Securities due August 31, 2029 with a face value of $250 million. As the securities are being redeemed at par, security holders will receive $25 per preferred security held, plus accrued and unpaid distributions to the redemption date. Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes, due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Proceeds from the remarketed notes will be held by a collateral agent and used to purchase U.S. Treasury securities to satisfy the forward stock purchase contract component of the Equity Units in November 2004. Duke Capital may exchange a significant portion of the remarketed notes for notes of different maturities.

Credit Facilities Capacity and Restrictive Debt Covenants. During the six months ended June 30, 2004, credit facilities capacity was reduced by approximately $760 million compared to December 31, 2003, primarily relating to the divested Australian operations. In addition, Duke Capital, Duke Energy Field Services, LLC (DEFS), Westcoast Energy Inc. (Westcoast) and Union Gas Limited renewed and replaced their credit facilities at lower amounts due to reduced need for credit capacity. The credit facilities as of June 30, 2004 are included in the following table. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the 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, 2004, 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 Facilities Summary as of June 30, 2004 (in millions)

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Other Borrowings		Total
Duke Capital LLC
$600 364-day syndicated ^{a, b, c}	June 2005
$600 three-year syndicated ^{a, b, c}	June 2007
Total Duke Capital LLC		$	1,200	$	—	$	618	$	—	$	618
Westcoast Energy Inc.
$74 two-year syndicated ^{b, d}	July 2005
$149 three-year syndicated ^{b, e}	June 2007
Total Westcoast Energy Inc.			223		—		—		—		—
Union Gas Limited
$223 364-day syndicated ^{f, g}	June 2005		223		—		—		—		—
Duke Energy Field Services, LLC
$250 364-day syndicated ^{c, h, i}	March 2005		250		—		—		—		—

Total ^j		$	1,896	$	—	$	618	$	—	$	618

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

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

^c	Credit facility contains an interest coverage covenant.

^d	Credit facility is denominated in Canadian dollars and was 100 million Canadian dollars as of June 30, 2004.

^e	Credit facility is denominated in Canadian dollars and was 200 million Canadian dollars as of June 30, 2004.

^f	Credit facility contains a covenant requiring that debt-to-total capitalization ratio not exceed 75%. Credit facility is denominated in Canadian dollars and was 300 million Canadian dollars as of June 30, 2004.

^g	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 first draw.

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

ⁱ	Credit facility contains a covenant requiring that the debt-to-total capitalization ratio not exceed 53%.

^j	Various operating credit facilities and credit facilities that support commodity, foreign exchange, derivative and intra-day transactions are not included in this credit facilities summary.

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 includes income allocated by Duke Energy of $7 million for the three month period ended June 30, 2004 and $6 million for the same period in 2003. The income allocated by Duke Energy was $13 million for the six month period ended June 30, 2004 compared to $12 million for the same period in 2003.

The following table shows the components of the Net Periodic Pension Costs for the Westcoast Canadian Retirement Plans.


Components of Net Periodic Pension Costs for Westcoast (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Service cost	$	2		$	1		$	4		$	3
Interest cost on projected benefit obligation		6			6			13			12
Expected return on plan assets		(6	)		(6	)		(12	)		(12	)
Amortization of loss		1			—			1			—

Net periodic pension costs	$	3		$	1		$	6		$	3

Duke Energy’s policy is to fund amounts on an actuarial basis to provide sufficient assets to pay benefits to U.S. plan participants. Duke Energy does not have a required contribution to the U.S. plan for 2004.

Duke Capital’s policy is to fund the Westcoast defined benefit retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate sufficient assets to pay benefits. Duke Capital has contributed $6 million to the Westcoast plans during the six-months ended June 30, 2004, and anticipates making total contributions of approximately $27 million in 2004.

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 the three month period ended June 30, 2004 and $5 million for the same period in 2003. The expense allocated by Duke Energy was $11 million for the six month period ended June 30, 2004 compared to $10 million for the same period in 2003.

The following table shows the components of the Net Periodic Post-Retirement Benefit Costs for the Westcoast Canadian Plans.


Components of Net Periodic Post-Retirement Benefit Costs for Westcoast (in millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Service cost benefit	$	1	$	1	$	1	$	1
Interest cost on accumulated post- retirement benefit obligation		1		1		2		2
Amortization of loss		—		—		1		—

Net periodic post-retirement benefit costs	$	2	$	2	$	4	$	3

6. Comprehensive Income and Accumulated Other Comprehensive Income

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


Total Comprehensive Income (in millions)

	Three Months Ended June 30						Six Months Ended June 30
	2004			2003			2004			2003
Net Income	$	277		$	302		$	373		$	377
Other comprehensive income
Foreign currency translation adjustments		(235	)		240			(278	)		404
Net unrealized gains on cash flow hedges ^a		44			237			167			420
Reclassification into earnings from cash flow hedges ^b		(63	)		(57	)		(57	)		(118	)

Other comprehensive (loss) income, net of tax		(254	)		420			(168	)		706

Total Comprehensive Income	$	23		$	722		$	205		$	1,083

^a	Net unrealized gains on cash flow hedges, net of $0 and $183 million tax expense for the three months ended 2004 and 2003, respectively, and $67 million and $269 million tax expense for the six months ended 2004 and 2003, respectively

^b	Reclassification into earnings from cash flow hedges, net of $19 million and $55 million tax benefit for the three months ended 2004 and 2003, respectively, and $17 million and $84 million tax benefit for the six months ended 2004 and 2003, respectively

Accumulated Other Comprehensive Income


Components of and Changes in Accumulated Other Comprehensive Income (in millions)

	Foreign Currency Adjustments			Net Gains on Cash Flow Hedges		Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
Balance as of December 31, 2003	$	309		$	316	$	(25	)	$	600
Other comprehensive income changes year-to-date (net of $50 tax expense)		(278	)		110		—			(168	)

Balance as of June 30, 2004	$	31		$	426	$	(25	)	$	432

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 is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for some income tax items.

In the second quarter of 2004, DEFS acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities.

Dispositions. For the six months ended June 30, 2004, the sale of other assets (which excludes assets held for sale as of June 30, 2004 and discontinued operations, both of which are discussed in Note 8, and sales by Crescent which are discussed separately below) resulted in approximately $107 million in proceeds, and

net losses of $10 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. Significant sales of other assets in 2004 are detailed by business segment as follows:

•

Natural Gas Transmission’s asset sales totaled $12 million in net proceeds. Those sales resulted in gains of $9 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Sales included the sale of storage gas related to the Canadian distribution operations in the second quarter of 2004.

•

Duke Energy North America’s (DENA’s) asset sales totaled $64 million in net proceeds. Those sales resulted in losses of $13 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included the sale of turbines and surplus equipment in the first and second quarter of 2004, some Duke Energy Trading and Marketing, LLC (DETM) contracts in the first and second quarter of 2004 (DETM held a net liability position in those contracts), and the sale of a 25% undivided interest in DENA’s Vermillion facility in the second quarter of 2004. Duke Capital still owns the remaining 75% interest in the Vermillion facility.

•

Asset sales within Other totaled $33 million in net proceeds. Those sales resulted in losses of $7 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach LLC in the first quarter of 2004.

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 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.

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., 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 Statements of Operations in the first quarter of 2004 in anticipation of this sale. The sale is expected to close in the third quarter of 2004.

The pro forma results of operations for acquisitions and dispositions do not materially differ from reported results.

8. Assets Held for Sale and Discontinued Operations

Assets Held for Sale. In 2003, Duke Capital decided to exit the merchant power generation business in the southeastern United States. In the first quarter of 2004, as a result of marketing efforts related to DENA’s eight plants in the region, Duke Capital classified the assets and associated liabilities as “held for sale” in the March 31, 2004 Consolidated Balance Sheet and recorded an approximate $360 million pre-tax loss on those assets, which represents the excess of the carrying value over the fair value of the plants, less estimated costs to sell. This loss was included in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. The fair value of the plants was based on the final sales price of $475 million, which Duke Capital announced it had agreed to with KGen Partners LLC (KGen) on May 4, 2004. The sales price consists of $425 million cash and a $50 million note receivable from KGen. The $50 million note receivable bears variable interest at LIBOR (London Interbank Offered Rate) plus 14.25% per annum, compounded quarterly, and is secured by a fourth lien on the assets of KGen’s owner, and matures with a balloon payment of principal and interest due no later than 7.5 years after closing date. The agreement includes the sale of all of Duke Capital’s merchant generation assets in the southeastern United States. The results of operations related to those assets are not reported in Discontinued Operations on the Consolidated Statements of 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 those assets.

Also in the first quarter of 2004, Duke Capital recorded a $238 million after-tax gain related to International Energy’s Asia Pacific power generation and natural gas transmission businesses. The estimated fair value, less costs to sell was classified as “held for sale” as of December 31, 2003. The gain recorded in the first quarter of 2004 restores the loss recorded during the fourth quarter of 2003. The December 31, 2003 estimated fair value was based on third-party bids received by International Energy. During the first quarter, Duke Capital determined that it was likely a bid in excess of the originally determined fair value would be accepted.

In April 2004, Duke Capital completed the sale of the Asia-Pacific businesses 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. Duke Capital 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 Asia-Pacific operations. The $840 million does not include approximately $50 million of Australian debt, which has been placed in trust and fully funded in connection with the closing of the sale transaction and will be repaid in September 2004. This trust is included in the Consolidated Financial Statements as Duke Capital is the primary beneficiary of the trust and, therefore, is required to consolidate the trust under provisions of FIN 46. The Asia-Pacific debt had been classified as Current and Non-Current Liabilities Associated with Assets Held for Sale on the December 31, 2003 Consolidated Balance Sheet. All gains related to this transaction and the results of operations for these assets are included in Net Gain (Loss) on Dispositions, net of tax, within Discontinued Operations, in the Consolidated Statements of Operations. See Note 4 for a discussion of the impact of this transaction to consolidated long-term debt.

In the second quarter of 2004, Duke Capital announced an agreement to sell one of DENA’s deferred facilities, Moapa, to Nevada Power Company for approximately $182 million in cash, with closing expected during the fourth quarter of 2004 pending regulatory approvals. The Moapa asset was classified as “held for sale” in the June 30, 2004 Consolidated Balance Sheet. This facility will not be reported in Discontinued Operations as, among other considerations, the facility never entered into operations and has no associated historical operating revenues or costs.

The following table presents the carrying values as of June 30, 2004 and December 31, 2003 of the major classes of Assets Held for Sale and associated liabilities in the Consolidated Balance Sheets. International Energy’s European operations, some turbines and related equipment owned by DENA and the merchant finance business conducted by Duke Capital Partners, LLC (DCP) were the material items classified as “held for sale” at both June 30, 2004 and December 31, 2003. The December 31, 2003 period also included International Energy’s Asia-Pacific power generation and natural gas transmission businesses, and the June 30, 2004 period also included DENA’s eight plants in the southeastern United States, DENA’s Moapa facility, and certain commercial office buildings owned by Crescent in which it expects continuing involvement through a third party leasing and management agreement with the new owners of the buildings.

Summarized Balance Sheet Information for Assets Held for Sale (in millions)


	June 30, 2004		December 31, 2003
Current assets	$	113	$	424
Investments and other assets		199		379
Property, plant and equipment, net		493		1,065

Total assets held for sale	$	805	$	1,868

Current liabilities	$	44	$	651
Long-term debt		—		514
Deferred credits and other liabilities		—		223

Total liabilities associated with assets held for sale	$	44	$	1,388

Discontinued Operations. The following table summarizes the operating results classified as Discontinued Operations in the Consolidated Statements of Operations. The three and six-month periods ended June 30, 2004 include the results for International Energy’s Asia-Pacific power generation and natural gas transmission businesses and its European operations, the merchant finance business conducted by DCP, and some other assets at Field Services. In addition, the three and six-month periods ended June 30, 2003 contains some Crescent real estate projects that were sold in 2003. For additional information related to the exit of those activities, see the Notes to the Consolidated Financial Statements in Duke Capital’s Annual Report on Form 10-K/A for the year ended December 31, 2003.

Discontinued Operations (in millions)


			Operating Income									Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)		Gain (Loss) on Dispositions, Net of Tax
Three Months Ended June 30, 2004
International Energy	$	19	$	(1	)	$	2		$	(3	)	$	39		$	9	$	30
Field Services		—		—			—			—			—			—		—
Crescent and Other		1		(1	)		—			(1	)		—			—		—

Total consolidated	$	20	$	(2	)	$	2		$	(4	)	$	39		$	9	$	30

Three Months Ended June 30, 2003
International Energy	$	196	$	14		$	(3	)	$	17		$	(1	)	$	—	$	(1	)
Field Services		98		3			1			2			19			7		12
Crescent and Other		8		—			3			(3	)		—			—		—

Total consolidated	$	302	$	17		$	1		$	16		$	18		$	7	$	11

Six Months Ended June 30, 2004
International Energy	$	82	$	3		$	1		$	2		$	295		$	27	$	268
Field Services		14		1			—			1			2			1		1
Crescent and Other		1		2			1			1			—			—		—

Total consolidated	$	97	$	6		$	2		$	4		$	297		$	28	$	269

Six Months Ended June 30, 2003
International Energy	$	408	$	15		$	(1	)	$	16		$	(1	)	$	—	$	(1	)
Field Services		237		7			2			5			19			7		12
Crescent and Other		17		(2	)		1			(3	)		—			—		—

Total consolidated	$	662	$	20		$	2		$	18		$	18		$	7	$	11

9. 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 offer different products and services, are managed separately and are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

Beginning in 2004, Crescent, formerly part of Other Operations, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages “legacy” land holdings primarily in the southeastern and southwestern United States. All other entities previously part of Other Operations and now within Other still remain, primarily: DukeNet Communications LLC, and Duke Capital’s 50% equity investment in Duke/Fluor Daniel (D/FD). Unallocated corporate costs are also recorded in Other in the table below.

Accounting policies for the 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/A for December 31, 2003. 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 and cash equivalents are managed centrally by Duke Capital, so the gains and losses on foreign currency remeasurement associated with cash balances, and interest income on those balances, are generally 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.

Business Segment Data (in millions)


	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
Three Months Ended June 30, 2004
Natural Gas Transmission	$	635	$	53		$	688		$	311
Field Services		2,337		19			2,356			94
Duke Energy North America		653		19			672			(39	)
International Energy		147		—			147			68
Crescent		101		—			101			87

Total reportable segments		3,873		91			3,964			521
Other		21		16			37			30
Eliminations		—		(107	)		(107	)		—
Interest expense		—		—			—			(263	)
Minority interest expense and other ^a		—		—			—			43

Total consolidated	$	3,894	$	—		$	3,894		$	331

Three Months Ended June 30, 2003
Natural Gas Transmission	$	636	$	56		$	692		$	306
Field Services		1,958		90			2,048			53
Duke Energy North America		915		47			962			211
International Energy		169		—			169			91
Crescent		76		—			76			21

Total reportable segments		3,754		193			3,947			682
Other		68		36			104			(1	)
Eliminations		—		(229	)		(229	)		—
Interest expense		—		—			—			(255	)
Minority interest expense and other ^a		—		—			—			(3	)

Total consolidated	$	3,822	$	—		$	3,822		$	423

^a	Includes interest income, foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

Business Segment Data (in millions)


	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
Six Months Ended June 30, 2004
Natural Gas Transmission	$	1,617	$	109		$	1,726		$	709
Field Services		4,635		96			4,731			186
Duke Energy North America		1,286		42			1,328			(596	)
International Energy		301		—			301			97
Crescent		140		—			140			147

Total reportable segments		7,979		247			8,226			543
Other		46		33			79			57
Eliminations		—		(280	)		(280	)		—
Interest expense		—		—			—			(536	)
Minority interest expense and other ^a		—		—			—			53

Total consolidated	$	8,025	$	—		$	8,025		$	117

Six Months Ended June 30, 2003
Natural Gas Transmission	$	1,515	$	145		$	1,660		$	729
Field Services		4,004		594			4,598			83
Duke Energy North America		2,223		135			2,358			234
International Energy		341		—			341			131
Crescent		97		—			97			21

Total reportable segments		8,180		874			9,054			1,198
Other		116		40			156			52
Eliminations		—		(914	)		(914	)		—
Interest expense		—		—			—			(520	)
Minority interest expense and other ^a		—		—			—			(1	)

Total consolidated	$	8,296	$	—		$	8,296		$	729

^a	Includes interest income, 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, intercompany current assets, intercompany derivative assets and investments in subsidiaries.

Segment Assets (in millions)


	June 30, 2004			December 31, 2003
Natural Gas Transmission	$	16,108		$	16,384
Field Services		6,803			6,417
Duke Energy North America		8,636			9,702
International Energy		3,228			4,550
Crescent		1,585			1,653

Total reportable segments		36,360			38,706
Other		2,370			1,945
Eliminations ^a		(473	)		(546	)

Total consolidated assets	$	38,257		$	40,105

^a	Represents elimination of intercompany assets, such as accounts receivable and interest receivable, that have been created based on “arm’s length transactions” (transactions that have been conducted as though the parties were unrelated).

Segment assets include goodwill of $3,855 million as of June 30, 2004 and $3,962 million as of December 31, 2003, with $3,124 million as of June 30, 2004 allocated to Natural Gas Transmission, $490 million to Field Services, $234 million to International Energy and $7 million to Crescent. The $107 million decrease from December 31, 2003 to June 30, 2004 was related solely to foreign currency exchange rate fluctuations of $99 million at Natural Gas Transmission, $5 million at International Energy and $3 million at Field Services.

10. Risk Management Instruments

The following table shows the carrying value of Duke Capital’s derivative portfolio as of June 30, 2004 and December 31, 2003.

Derivative Portfolio Carrying Value (in millions)


	June 30, 2004			December 31, 2003
Hedging	$	653		$	439
Trading		155			185
Undesignated		(362	)		(220	)

Total	$	446		$	404

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 fair value, except that the net asset amounts for hedging include assets of $196 million as of June 30, 2004 and $267 million as of December 31, 2003, 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. Those balances will reduce upon settlement of the associated contracts.

The $214 million increase in the hedging derivative portfolio carrying value is due primarily to increases in forward gas prices, partially offset by the realization of gas hedge gains as well as other hedge activity.

The $142 million decrease in the undesignated derivative portfolio fair value is due primarily to increases in power and gas prices on forward contracts formerly designated as hedges of future production from DENA’s southeastern plants and deferred western plants along with settlements of net mark-to-market gains during the six months ended June 30, 2004, partially offset by other hedge activity.

Changes in Fair Value of Duke Capital’s Trading Contracts During 2004 (in millions)


Fair value of contracts outstanding as of December 31, 2003	$	185
Contracts realized or otherwise settled during the year		(36	)
Other changes in fair values		6

Fair value of contracts outstanding as of June 30, 2004	$	155

11. Regulatory Matters

FERC Orders No. 2004, 2004-A and 2004-B (Standards of Conduct). In November 2003, the Federal Energy Regulatory Commission (FERC) issued Order 2004, which harmonizes the standards of conduct applicable to natural gas pipelines and electric transmitting public utilities (“Transmission Providers”) previously subject to differing standards. In December 2003, Duke Energy filed a request for clarification and rehearing with the FERC regarding: (1) restrictions on how companies and their affiliates interact and share information, including corporate governance information, and (2) expansion of coverage to affiliated gatherers, processors, and intrastate and Hinshaw pipelines. (A Hinshaw pipeline is a regulated pipeline company engaged in the transportation of interstate natural gas or the sale of interstate natural gas for resale. A Hinshaw pipeline company receives natural gas from another person within or at the boundary of a state, and then consumes that natural gas within that state.) On April 16, 2004, the FERC issued Order 2004-A, revising the standards of conduct governing information flow between Transmission Providers and their “energy affiliates.” Order 2004-A accommodates unique corporate governance issues raised by Duke Capital’s corporate structure and clarifies provisions governing information flow for governance purposes. The FERC also clarified the rules’ expanded coverage to gatherers, processors, and intrastate and Hinshaw pipelines. On August 2, 2004, the FERC issued Order 2004-B, reaffirming the previous two orders and providing clarification on a number of issues. Duke Capital has implemented compliance programs to meet the requirements of the order related to information flow and governance processes. Duke Capital expects to be in full compliance with the orders, including significant training and information posting requirements, by the September 22, 2004 deadline, and expects the orders to have no material adverse effect on its consolidated results of operations, cash flows or financial position.

Natural Gas Transmission. Rate Related Information. On December 1, 2003, The British Columbia Pipeline System (BC Pipeline) filed an application with the National Energy Board (NEB) for approval of 2004 tolls. In March 2004, BC Pipeline reached an agreement in principle with its major stakeholders to establish tolls for the period from January 1, 2004 through December 31, 2005. On June 30, 2004, BC Pipeline filed an application with the NEB for approval of the 2004 tolls established in the settlement agreement.

Union Gas Limited (Union Gas) filed cost of service evidence with the Ontario Energy Board (OEB) in 2003 to establish rates for 2004. The OEB issued a decision in March 2004 and Union Gas implemented these rates in May 2004.

Maritimes & Northeast Pipeline LLC filed its Section 4 rate case with the FERC on June 30, 2004 seeking an increase in rates from $0.695 per Decatherm (Dth) to $1.07/Dth. The FERC has issued an order accepting the rate filing and suspending the rates until January 1, 2005, at which time they will become effective, subject to refund. The rate case has been set for hearing.

12. 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. Duke Capital and its affiliates are responsible for environmental remediation at various impacted properties and contaminated sites, similar to others in the energy industry. 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. These matters typically involve management of contaminated soils and may involve ground water remediation. Managed in conjunction with relevant federal, state and local agencies, they vary with respect to site conditions and locations, remedial requirements, complexity and sharing of responsibility. If they 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 the respective business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows or financial position.

Air Quality Control. In 1998, the Environmental Protection Agency (EPA) issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans (SIPs) to significantly reduce emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various states, industry and other interests, including Duke Energy. In 2000, the court upheld most aspects of the EPA rule. The same court subsequently extended the compliance deadline for emission reductions to May 31, 2004. In 2003, Duke Capital incurred the capital costs necessary for emissions controls to meet the requirements of the EPA’s rule.

Global Climate Change. The United Nations-sponsored Kyoto Protocol prescribes specific greenhouse gas emission reduction targets for developed countries as a response to concerns over global warming and climate change. The focus is on lowering emissions at the source, including fossil-fueled electric power generation and natural gas operations. Canada is presently the only country in which Duke Capital has assets that would have a greenhouse gas reduction obligation under the Kyoto Protocol. If Russia ratifies the Kyoto Protocol, it will enter into force and Canada will be obligated to reduce its average greenhouse gas emissions to 6% below 1990 levels over the period 2008 to 2012. In anticipation of the Protocol’s entry into force, the Canadian government is developing an implementation plan that includes a carbon dioxide (CO₂) cap and trade program for large final emitters (LFE), and Parliament may consider authorizing legislation by the end of 2004 or early 2005. If an LFE program is enacted, then all of Duke Capital’s Canadian operations would likely be subject to such a program, with compliance options ranging from the purchase of CO₂ emissions credits to actual emissions reductions at the source, or a combination of strategies. It is unclear how, or if, Canada’s current CO₂ emissions management policy direction might change if Russia fails to ratify the Protocol. The recent Canadian elections, which resulted in a minority government led by the Liberal party, might also affect the final policy timing and outcome.

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 CO₂emissions reductions, none have advanced through the legislature. Presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO₂ emissions reduction program being enacted in the near future, or the specific requirements of any such regime that were to become law, is highly uncertain. Some states are contemplating or have taken steps to manage greenhouse gas emissions, and while a number of states in the Northeast and far West recently began discussing the possibility of regional greenhouse gas reduction programs in the future, the outcome of such discussions is very uncertain. If significant greenhouse gas emissions reduction policies are legally adopted or promulgated in the United States or its various states, those requirements could have far-reaching and significant implications for industry in those jurisdictions, including the respective energy sectors.

Duke Capital cannot estimate with certainty the potential effect of the Canadian greenhouse gas reduction policy currently under development, or estimate the potential effect of U.S. federal or state level greenhouse gas policy on future consolidated results of operations, cash flows or financial position due to the uncertainty of the Canadian policy and the speculative nature of U.S. federal and state policy. Duke Capital

will continue to assess and respond to the potential implications of greenhouse gas policies applicable to Duke Capital’s business operations in the United States, Canada and Latin America.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities were accruals related to extended environmental-related activities of $80 million as of June 30, 2004 and $85 million as of December 31, 2003. The accrual for extended environmental-related activities represents Duke Capital’s provisions for costs associated with remediation activities at some of its current and former sites and certain other environmental matters. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows or financial position.

Litigation

Western Energy Litigation. Commencing in 2000, plaintiffs have filed 31 lawsuits in state and federal courts in California, Montana, Oregon and Washington against energy companies, including Duke Capital affiliates, and current and former Duke Capital executives. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers residing in the states of California, Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana. 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, eight suits have been dismissed on filed rate and federal preemption grounds. Plaintiffs are appealing the dismissals. One suit was dismissed voluntarily.

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 agreement involving FERC refunds and other proceedings. This agreement (the California Settlement) is addressed in more detail in the Western Energy Regulatory Matters and Investigations section below.

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, based on rulings by trial courts and the California Settlement, 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. Subsequent rulings by appellate courts could significantly affect the outcome.

In 2003, Pacific Gas and Electric Company (PG&E) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of a bilateral power contract between the parties in early 2001. PG&E sought in excess of $25 million from DETM pursuant to a disputed “true-up” agreement between the parties. The PG&E true-up dispute was resolved in connection with the California Settlement.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM 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 excess of $80 million. This dispute is not resolved in the California Settlement. 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. Several investigations and regulatory proceedings at the state and federal levels are looking into the causes of high wholesale electricity prices in the western United States during 2000 and 2001. Duke Capital has resolved these issues, which are described in detail below, through the California Settlement.

In FERC refund proceedings, the FERC has ordered some sellers, including DETM, to refund, or to offset against outstanding accounts receivable, amounts billed for electricity sales in excess of a FERC-established proxy price. In 2002, the presiding administrative law judge in the FERC refund proceedings issued preliminary estimates that indicated DETM had refund liability of approximately $95 million.

The FERC issued staff recommendations and an order in 2003 relating to the refund proceeding and investigations into the causes of high wholesale electricity prices in the western United States during 2000 and 2001. The order modified the prior refund methodology by changing the gas proxy price used in the refund calculation. Duke Capital cannot predict with certainty the outcome of the methodology change, but Platts, an energy industry publication, reported that a FERC spokesman announced that the methodology change could increase the total aggregate refund amount for all generators from $1.8 billion to at least $3.3 billion. The 2003 order allowed generators to receive a gas cost credit in instances where companies incurred fuel costs exceeding the gas proxy price. DENA and DETM submitted gas cost data to the FERC and sought a gas price credit in the range of $72 million. The California parties challenged both the amount and availability of the credit. Resolution of the refund proceeding is included in the California Settlement.

In 2003, the FERC issued an Order to Show Cause concerning “Enron-type gaming behavior,” and a companion order requiring suppliers, including DETM, to justify bids in the CAISO and CalPX markets made above the level of $250 per megawatt hour from May 1, 2000 through October 1, 2000. Also in 2003, the FERC Staff and Duke Energy announced two agreements to resolve all matters at issue in both of those orders. Duke Capital agreed to pay up to $4.59 million to benefit California and western electricity consumers, pending final approval by the FERC. The FERC approved the agreement involving bidding practices and rejected the California parties’ objections to the agreement. The California parties sought review of the FERC’s ruling on this agreement from the 9th Circuit U.S. Court of Appeals. On April 19, 2004, the administrative law judge reviewing the remaining agreement approved the settlement and rejected the California parties’ objections. That agreement was submitted to the FERC for review. The California parties’ challenge of the two agreements is resolved through the California Settlement.

At the state level, the California Public Utilities Commission (CPUC), a California State Senate Select Committee, the California Attorney General (with participation by the Attorneys General of Washington and Oregon) and the San Diego District Attorney are conducting formal and informal investigations involving Duke Capital regarding the California energy markets, including review of alleged manipulation of energy prices. In addition, 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. All investigations, other than criminal investigations, are resolved through the California Settlement. Duke Capital does not believe the outcome of any remaining criminal investigation will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In July 2004, Duke Energy reached an agreement in principle (the California Settlement), to settle the FERC refund proceedings and other significant litigation related to the western energy markets during 2000-2001. The parties to the settlement agreement include the FERC staff, the state of California, the state of Washington, the state of Oregon, PG&E, SCE, San Diego Gas & Electric Company, the California Department of Water Resources, the CPUC staff, private litigants and Duke Energy. The settlement is subject to approval by the FERC and the CPUC, and the class-action settlements are subject to court approval.

As part of the agreement, Duke Capital will provide approximately $208 million in cash and credits. In exchange, the parties to the agreement will forgo all claims relating to refunds or other monetary damages

for sales of electricity during the settlement period, and claims alleging Duke Capital received unjust or unreasonable rates for the sale of electricity during the settlement period. The settlement resolves:

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All western refund proceedings pending before the FERC

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Market price investigations by attorneys general in California, Washington and Oregon

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Private electricity-related class-action litigation filed on behalf of California, Washington, Oregon, Idaho and Utah ratepayers

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Natural gas price issues raised by the California attorney general, PG&E, SCE and San Diego Gas & Electric Company.

Duke Capital recorded an approximate $105 million pre-tax charge in the second quarter of 2004 at DENA to reflect the settlement agreement. This charge was recorded in Operation, Maintenance and Other on the Consolidated Statements of Operations.

Financial Effect of California Settlement (in millions)


Cash	$	85
Write-off of receivables and credits due to Duke Capital		123

Settlement total		208
Reserves and offsets		(103	)

Second quarter 2004 pre-tax earnings impact	$	105

Trading Related Litigation. Beginning in 2002, 17 shareholder class-action lawsuits were filed against Duke Energy: 13 in the U.S. District Court for the Southern District of New York and four in the U.S. District Court for the Western District of North Carolina. These lawsuits arose out of allegations that Duke Energy improperly engaged in “round trip” trades which resulted in an alleged overstatement of revenues over a three-year period. By late 2003, the two federal courts had dismissed all 17 lawsuits. Plaintiffs in the New York cases have appealed the dismissal order to the 2nd Circuit U.S. Court of Appeals. Duke Energy intends to vigorously defend against that appeal. By letter dated April 16, 2004, Duke Energy received notice that a shareholder has reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same issues raised in the dismissed shareholder lawsuits, the notice states that the shareholder intends to initiate derivative shareholder litigation within 90 days from the date of the letter. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds to 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.

Since August 2003, plaintiffs have filed three class-action lawsuits in 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. The lawsuits initially named Duke Energy as a defendant, along with numerous other entities. In the latest consolidated complaint filed in January 2004, the plaintiffs dropped Duke Energy from the cases and added DETM as a defendant. Claiming 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. These cases are in very early stages. It is not possible to predict whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur.

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. The investigation remains open, and Duke Capital cannot predict the outcome.

On April 21, 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 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 2004, Duke Energy received a request for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activity of a former DETM trader. Duke Capital affiliates are cooperating with the government in this investigation and cannot predict the outcome.

Sonatrach/Citrus Trading Corporation (Citrus). Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration 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. Sonatrading and Sonatrach claim that Duke LNG repudiated the LNG Agreements by allegedly failing to perform LNG marketing obligations. In 2003, an arbitration panel issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping, making them liable to Duke LNG for any resulting damages. The panel also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. Also in 2003, Sonatrading terminated the LNG Agreements and seeks to recover resulting damages from Duke LNG. The final hearing on damages issues has been tentatively scheduled for September 2005.

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 Texas against Duke LNG (now pending in U.S. District Court in Houston, Texas) 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 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. On March 16, 2004, Citrus filed suit against PanEnergy Corp in Harris County, Texas district court, alleging that PanEnergy is financially responsible for losses incurred by Citrus as a result of Duke LNG’s alleged breaches. The action against PanEnergy has now been consolidated with the original Citrus lawsuit in federal court. No trial date has been set, and discovery is proceeding. 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.

Enron Bankruptcy. In December 2001, Enron filed for relief pursuant to Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Other Enron affiliates have since filed for bankruptcy. Duke Capital affiliates engaged in transactions with various Enron entities prior to the bankruptcy filings. In 2001, Duke Capital recorded a reserve to offset its exposure to Enron. In 2002, various Enron trading entities demanded payment from DETM for some energy commodity

sales transactions without regard to any set-off rights. DETM filed an adversary proceeding against Enron, seeking, among other things, a declaration affirming each plaintiff’s right to set off its respective debts to Enron. In 2003, DETM and other Duke Capital affiliates entered into an agreement in principle with Enron and its trading entities to resolve the outstanding disputes pending before the bankruptcy court. The proposed agreement was approved by the Unsecured Creditor’s Committee and on March 11, 2004, the bankruptcy court approved the settlement. No party appealed the court’s approval of the agreement prior to the April 12, 2004 deadline, and the agreement is now final. The terms of the agreement are confidential but resulted in a net pre-tax gain in the second quarter of 2004 of approximately $109 million (net of minority interest expense of $5 million), due to the write-off of net payables to Enron that were on the Consolidated Balance Sheet. Of the gain, $113 million was recorded at DENA and $1 million at Field Services as a credit to Operation, Maintenance and Other on the Consolidated Statements of Operations.

ExxonMobil Disputes. On April 8, 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 affiliates 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 exemplary damages not clearly quantified in the arbitration demand. Duke Energy denies these allegations, will vigorously defend against ExxonMobil’s claims, and has filed counterclaims asserting that ExxonMobil breached its Ventures obligations and other contractual obligations. These matters are in very early stages. It is not possible to predict with certainty whether Duke Capital or any of its affiliates will incur any liability as a result of these matters, or to estimate the damages, if any, that might be incurred.

On November 13, 2003, MNGI filed a Demand for Arbitration against Duke Energy and DETMI. MNGI claims that, under the terms of the limited liability company agreement of DETM and general fiduciary principles, DETMI and Duke Energy have full financial responsibility for the settlement reached between DETM and the Commodity Futures Trading Commission (CFTC). MNGI demands reimbursement for a 40% share of the $28 million CFTC settlement, plus 40% of all related expenses incurred by DETM. On March 5, 2004, MNGI filed an amended claim, adding DENA as a party. In June 2004, the parties settled the dispute. Due to a previously established reserve, the settlement did not have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Other Litigation and Legal Proceedings. Duke Capital and its subsidiaries are involved in other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies 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 consolidated results of operations, cash flows or financial position.

13. 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 (the DOE) under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a MOX fuel fabrication facility (the MOX FFF). 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, 2004, 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 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, 2004, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and an initial option phase.

DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions as recently clarified in a contract amendment to 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, 2004, 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 its Duke Power franchised electric business, 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 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, 2004, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase.

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 Prime Contract. 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:

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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

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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 and

•

the U.S. Congress will authorize funding for DCS’ work under the Prime Contract, which will affect DCS’ decision whether to exercise its options under the Duke Power Subcontract.

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, 2004 was approximately $2.3 billion. Of this amount, approximately $1.5 billion relates to guarantees of payments and performance of affiliated entities such as Duke Energy Merchants, LLC (DEM), and approximately $475 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $130 million of the performance guarantees expire between 2004 and 2005, and approximately $400 million expires in 2006 and thereafter; the remaining performance guarantees have 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 projects, 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 an unconsolidated 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, 2004 was approximately $100 million. Of those guarantees, approximately $30 million expire from 2004 to 2006, with the remainder expiring after 2006 or 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. Most of these letters of credit expire in 2004. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of June 30, 2004 was approximately $100 million. Of this amount, approximately $15 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities and approximately $10 million relates to affiliate entities such as DEM.

Duke Capital has guaranteed the issuance 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, 2004, Duke Capital had guaranteed approximately $125 million of outstanding surety bonds related to obligations of non-wholly owned entities. Of this amount, approximately $25 million relates to affiliated entities such as DEM, and approximately $15 million relates to obligations of less than wholly owned consolidated entities. The majority of these bonds expire in various amounts between 2004 and 2005.

Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned 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 non-consolidated entity. As of June 30, 2004, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, with no contractual expiration. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly-owned entities, most of which expire in 2004.

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 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 goods and services provided. 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 Duke Solutions guarantees. Further, Duke Capital granted indemnification to the buyer 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 2004 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.

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 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, including uncertainty as to whether claims will be made.

As of June 30, 2004, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

14. New Accounting Standards

The following new accounting standards have been adopted by Duke Capital subsequent to January 1, 2003 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” In April 2003, the FASB issued SFAS No. 149, which amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities, including the qualifications for the normal purchases and normal sales exception, under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This amendment reflects decisions made by the FASB and the Derivative Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 are to be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The provisions of SFAS No. 149 which resulted from the DIG process and became effective in quarters beginning before June 15, 2003 continue to be applied based on their original effective dates. Duke Capital adopted the provisions of SFAS No. 149 on July 1, 2003. Certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity led Duke Capital to re-evaluate its accounting policy for forward sales contracts. As a result, Duke Capital elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges on a prospective basis. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 will continue to be accounted for under such exception, including any modifications to those contracts, as long as the requirements for applying the normal purchases and normal sales exception are met.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” In May 2003, the FASB issued SFAS No. 150 which establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equities. Under SFAS No. 150, those instruments are required to be classified as liabilities in the statement of financial position. The financial instruments affected include certain financial instruments that require or may require the issuer to buy back some of its shares in exchange for cash or other assets, and certain obligations that can be settled with shares of stock. SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and has been applied to Duke Capital’s existing financial instruments beginning July 1, 2003.

Duke Capital’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited-life entities, which are required to be liquidated or dissolved on a certain date, based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests under FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” Duke Capital has a controlling interest in a limited-life entity in Bolivia, which is required to be liquidated 99 years after formation. A non-controlling interest in the entity is held by third parties. Upon termination or liquidation of the entity in 2094, the remaining assets of the entity are to be sold, the liabilities liquidated and any remaining cash distributed to the owners based upon their ownership percentages. As of June 30, 2004 the carrying value of the entity’s non-controlling interest of approximately $47 million approximates its fair value. Duke Capital continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on Duke Capital’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant future changes could be made by the FASB. Therefore, Duke Capital is not able to conclude whether such future changes would materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.

FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51,” which supercedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FASB Staff Positions related to the application of FIN 46.

The provisions of FIN 46 apply immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R are required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Capital). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Capital), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Capital). FIN 46 and FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 and FIN 46R also require certain disclosures of an entity’s relationship with variable interest entities.

Duke Capital has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003 which require consolidation or disclosure under FIN 46R. Under the

provisions of FIN 46R, effective March 31, 2004, Duke Capital has consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These entities, which are substantive entities, had total assets of approximately $210 million as of June 30, 2004. As a result of consolidating these entities, inclusive of intercompany eliminations, the impact to Duke Capital’s total assets was not material. Duke Capital adopted the provisions of FIN 46R on December 31, 2003, related to its special-purpose entities consisting of its remaining trust subsidiary that had issued trust preferred securities. Since Duke Capital is not the primary beneficiary of its remaining trust subsidiary, this entity has been deconsolidated in the accompanying Consolidated Financial Statements. As a result, affiliate debt to the trust is reflected in Long-term Debt in the Consolidated Balance Sheets. Interest paid to the subsidiary trust is classified as Interest Expense in the accompanying Consolidated Statements of Operations for periods after December 31, 2003. Additionally, Duke Capital previously had a significant variable interest in, but was not the primary beneficiary of, DCS. However, as further discussed in Note 13, Duke Capital no longer holds a significant variable interest in DCS as a result of the clarification in a contract amendment received in April 2004.

Various changes and clarifications to the provisions of FIN 46 have been made by the FASB since its original issuance in January 2003. While not anticipated at this time, any additional clarifying guidance or further changes to these complex rules could have an impact on Duke Capital’s Consolidated Financial Statements.

EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” In May 2003, the EITF reached consensus in EITF Issue No. 01-08 to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” Duke Capital has historically provided and leased storage capacity to outside parties, as well as entered into pipeline and electricity capacity agreements, both as the lessee and as a lessor. The accounting requirements under the consensus may impact the timing of revenue and expense recognition, and amounts previously reported as revenues may be required to be reported as rental or lease income. Should capital lease treatment be necessary, purchasers of transportation, and storage services are required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired on or after July 1, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for under historical accounting. The adoption of EITF Issue No. 01-08 did not have a material effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In July 2003, the EITF reached consensus in EITF Issue No. 03-11 that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on relevant facts and circumstances and the economic substance of the transaction. In analyzing those facts and circumstances, EITF Issue No. 99-19, “Reporting Revenue Gross as a Principle versus Net as an Agent,” and APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF Issue No. 03-11 was effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF Issue No. 03-11 did not have a material effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

FASB Staff Position (FSP) 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 FAS 106-2, which superseded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). The 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 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 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 Postretirement 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 FAS 106-2 are effective for the first interim period beginning after June 15, 2004 for all public companies, with early application encouraged. Duke Capital participates in the Duke Energy post-retirement benefit plan. Duke Energy adopted FSP FAS 106-2 retroactively to the date of enactment of the Act, December 8, 2003, as allowed by the FSP. As a result, Duke Energy’s accumulated post-retirement benefit obligation decreased by $96 million. The effect of Duke Capital’s net periodic post-retirement benefit cost was not material for the three and six months ended June 30, 2004.

The following new accounting standard has been issued, but has not yet been fully adopted by Duke Capital as of June 30, 2004:

Revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” In December 2003, the FASB revised the provisions of SFAS No. 132 to include additional disclosures related to defined-benefit pension plans and other defined-benefit post-retirement plans, such as the following:

•

The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used

•

Information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc.) along with the targeted allocation percentage of plan assets for each category and the actual allocation percentages at the measurement date

•

The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate

•

The current best estimate of the range of contributions expected to be made in the following year

•

The accumulated benefit obligation for defined-benefit pension plans

•

Disclosure of the measurement date utilized.

Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of revised SFAS No. 132 do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of revised SFAS No. 132 were applied by Duke Capital effective December 31, 2003 with the interim period disclosures applied for the quarter ended June 30, 2004, except for the disclosure provisions of estimated future benefit payments which will be effective for Duke Capital for the year ending December 31, 2004.

15. Subsequent Events

On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owed 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 these changes, Duke Capital will recognize a federal and state tax expense of approximately $900 million in the third quarter of 2004 from the elimination of the deferred tax assets that existed on its balance sheet prior to the July 2, 2004 reorganization. Correspondingly, Duke Energy, the parent of Duke Capital, will reflect, through consolidation, the elimination of the $900 million deferred tax asset at Duke Capital and the creation of a deferred tax asset of approximately $900 million on its balance sheet. Duke Energy will additionally recognize an approximate $45 million income tax benefit and corresponding deferred tax asset as a result of restating its deferred taxes to reflect a change in state tax rates. In future periods, as these deferred tax assets are converted into cash due to the realization of certain tax losses, Duke Energy intends to infuse the related cash flows back into Duke Capital. Most of these cash

benefits result from tax losses arising from the sales of DENA’s southeastern U.S. generation assets and the Moapa facility.

In July 2004, Duke Energy entered into the California Settlement, an agreement in principle to settle the FERC refund proceedings and other significant litigation related to the western energy markets during 2000-2001. For information related to this agreement, see Note 12.

On May 4, 2004 Duke Capital announced the sale of its merchant generation business in the southeastern United States to KGen. The sale transaction has obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a cumulative pre-tax loss of approximately $367 million, of which approximately $360 million was recognized in the first quarter of 2004 to reduce the carrying value of those assets to their estimated fair values, while the remaining amount of the loss will be recognized by Duke Capital in the third quarter of 2004. Subsequent to the closing of the transaction, DENA will continue to provide certain transitional services and operating and maintenance services for the sold assets, including potential exercise of limited plant dispatch rights for a period not to exceed six months from August 5, 2004. DENA anticipates recognizing the sale transaction in the third quarter of 2004 pending resolution of certain continuing involvement provisions.

In conjunction with the sale of DENA’s southeastern assets to KGen, Duke Capital arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from its Murray facility to Georgia Power. Duke Capital is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Capital for any payments made by it under the letter of credit, as well as expenses incurred by Duke Capital in connection with the letter of credit. Duke Capital will operate the Murray facility under an operation and maintenance agreement with a KGen subsidiary.

For information on subsequent events related to debt and credit facilities, see Note 4.

Item 2.

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

INTRODUCTION

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

Overview of Business Strategy and Economic Factors

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 an 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/A for the year ended December 31, 2003.

RESULTS OF OPERATIONS

Results of Operations and Variances (in millions)


	Three Months Ended June 30,								Six Months Ended June 30,
	2004			2003^a		Increase (Decrease)			2004			2003 ^a			Increase (Decrease)
Operating revenues	$	3,894		$	3,822	$	72		$	8,025		$	8,296		$	(271	)
Operating expenses		3,400			3,376		24			7,186			7,313			(127	)
Gains on sales of investments in commercial and multi-family real estate		62			9		53			121			11			110
(Losses) gains on sales of other assets, net		(13	)		1		(14	)		(365	)		2			(367	)

Operating income		543			456		87			595			996			(401	)
Other income and expenses, net		92			261		(169	)		137			331			(194	)
Interest expense		263			255		8			536			520			16
Minority interest expense		41			39		2			79			78			1

Earnings from continuing operations before income taxes		331			423		(92	)		117			729			(612	)
Income tax expense from continuing operations		80			148		(68	)		17			248			(231	)

Income from continuing operations		251			275		(24	)		100			481			(381	)
Income from discontinued operations, net of tax		26			27		(1	)		273			29			244

Income before cumulative effect of change in accounting principle		277			302		(25	)		373			510			(137	)
Cumulative effect of change in accounting principle, net of tax and minority interest		—			—		—			—			(133	)		133

Net income	$	277		$	302	$	(25	)	$	373		$	377		$	(4	)

^a	As revised, see Note 1 to the Consolidated Financial Statements

Overview of Drivers and Variances

Three Months Ended June 30, 2004 as Compared to June 30, 2003. Net income decreased for the quarter, compared to the prior year. Significant increases for the quarter included:

•

A $109 million (net of minority interest) pre-tax gain related to the settlement of the Enron bankruptcy proceedings (see Note 12 to the Consolidated Financial Statements)

•

A $39 million net increase in the net pre-tax gain ($30 million increase to the after tax gains) originally recorded on the sales of International Energy’s Asia-Pacific power generation and natural gas transmission business (see Note 8 to the Consolidated Financial Statements) and its European operations

•

The release of various income tax reserves totaling approximately $45 million (see Note 1 to the Consolidated Financial Statements)

•

Increased earnings at Crescent, due to the sale of the Alexandria land tract in the Washington, D.C. area and increased residential developed lot sales, and

•

Increased earnings at Field Services, due primarily to the favorable effects of commodity prices, net of hedging.

Those items were offset by:

•

A $105 million pre-tax charge related to the California and western U.S. energy markets settlement (see Note 12 to the Consolidated Financial Statements)

•

A $175 million pre-tax gain in 2003 from the sale of Duke Energy North America’s (DENA’s) 50% interest in Duke/UAE Ref-Fuel, and

•

An $80 million decrease in DENA’s 2004 total gross margin from lower net sales, lower values realized from hedge positions and lower mark-to-market earnings.

Six Months Ended June 30, 2004 as Compared to June 30, 2003. In addition to the quarterly items described above, significant items that contributed to the change in net income for the six months included:

•

A $256 million pre-tax gain ($238 million net of tax) recorded in the first quarter of 2004 on the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business (see Note 8 to the Consolidated Financial Statements)

•

Charges in 2003 related to changes in accounting principles of $133 million, net of tax and minority interest

•

Increased 2004 earnings at Field Services due to improved results from trading and marketing activities, and

•

Increased land management (“legacy” land sales) at Crescent, due to several large sales closed in the first quarter of 2004.

Those items were partially offset by:

•

An approximate $360 million pre-tax charge in the first quarter of 2004 associated with the announced sale of DENA’s southeastern plants (see Note 8 to the Consolidated Financial Statements), and

•

An additional $229 million decrease in DENA’s 2004 total gross margin from lower net sales, lower values realized from hedge positions and lower mark-to-market earnings.

On a consolidated and a segment reporting basis, June 30, 2004 results may not be indicative of the full year. Management has not changed its financial outlook for the remainder of the year for Duke Capital, nor the estimated EBIT growth targets for any of the business segments over the next three years.

Consolidated Operating Revenues

Three Months Ended June 30, 2004 as Compared to June 30, 2003. The increase was driven by a $73 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues. That increase was driven by increased revenues at Field Services, due primarily to increased natural gas and NGL prices, partially offset by decreased revenues at DENA related to decreased sales volumes as a result of the wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Capital’s 60/40 joint venture with ExxonMobil Corporation).

Six Months Ended June 30, 2004 as Compared to June 30, 2003. The decrease was driven by a $373 million decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, due primarily to:

•

Decreased revenues at DENA related to decreased sales volumes as a result of the wind-down of DETM and decreased gas prices, partially offset by

•

Increased revenues at Field Services, due primarily to an increase in NGL prices and volumes.

Partially offsetting the decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues was a $102 million increase in Regulated Natural Gas revenues, due primarily to foreign currency impacts related to Natural Gas Transmission’s Canadian operations due to the strengthening Canadian dollar.

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

Consolidated Operating Expenses

Three Months Ended June 30, 2004 as Compared to June 30, 2003. The increase was driven by a $156 million increase in Fuel Used in Electric Generation and Purchased Power which was due primarily to increased plant fuel costs at DENA, due primarily to overall higher average realized natural gas prices due to lower value recognized from financial gas hedges.

Partially offsetting the above increase was a $65 million decrease in Natural Gas and Petroleum Products Purchased, due primarily to:

•

Decreased natural gas purchases at DENA as a result of the continued wind down of DETM’s operations, partially offset by

•

Increased costs for raw natural gas at Field Services.

Also offsetting the above increase was a $32 million decrease in Operation, Maintenance and Other, due primarily to:

•

The pre-tax gain related to the settlement of the Enron bankruptcy proceedings, as previously described, partially offset by

•

The charge related to the California and western U.S. energy markets settlement, as previously described.

Six Months Ended June 30, 2004 as Compared to June 30, 2003. The decrease was driven by a $334 million decrease in Natural Gas and Petroleum Products Purchased, due primarily to decreased natural gas purchases at DENA as a result of the continued wind down of DETM’s operations.

Partially offsetting the above decrease was a $152 million increase in Fuel Used in Electric Generation and Purchased Power, due to the same factors that caused the quarterly variance, as described above.

Also offsetting the above decrease was a $70 million increase in Operation, Maintenance and Other, due primarily to:

•

The charge related to the California and western U.S. energy markets settlement, as previously described

•

Increased foreign currency impacts related to Natural Gas Transmission’s Canadian operations due to the strengthening Canadian dollar, and

•

An increase in the volume of Crescent’s developed lot sales, partially offset by

•

The pre-tax gain related to the settlement of the Enron bankruptcy proceedings, as previously described.

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, 2004 as Compared to June 30, 2003. The increase was due to a $49 million increase in real estate land sales due primarily to the sale of the Alexandria land tract in the Washington, D.C. area in June 2004.

Six Months Ended June 30, 2004 as Compared to June 30, 2003. The increase was due primarily to:

•

A $20 million increase in commercial project sales, due to the sale of a commercial project in the Washington, D.C. area in March 2004, compared to no commercial project sales in the first six months of 2003

•

A $49 million increase in real estate land sales due primarily to the sale of the Alexandria land tract in the Washington, D.C. area in June 2004, and

•

A $42 million increase in “legacy” land sales, due to several large sales closed in the first quarter of 2004.

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

Three Months Ended June 30, 2004 as Compared to June 30, 2003. Consolidated (losses) gains on sales of other assets for the quarter were relatively flat, compared to the prior year quarter.

Six Months Ended June 30, 2004 as Compared to June 30, 2003. The decrease was due primarily to an approximate $360 million loss in 2004 associated with the announced sale of DENA’s southeastern plants, as discussed above.

Consolidated Operating Income

Three Months Ended June 30, 2004 as Compared to June 30, 2003. The increase was due primarily to:

•

Increased operating income at Field Services, due to the favorable effects of commodity prices, net of hedging, and

•

Increased operating income at Crescent, due to the sale of the Alexandria land tract in the Washington, D.C. area and increased residential developed lot sales, partially offset by

•

Decreased operating income at DENA, due primarily to decreased total gross margin from lower net sales, lower values realized from hedge positions and lower mark-to-market earnings.

Six Months Ended June 30, 2004 as Compared to June 30, 2003. The decrease was due primarily to:

•

Decreased operating income at DENA, due primarily to the 2004 loss on the sale of DENA’s southeastern plants, and decreased total gross margin from lower net sales, lower values realized from hedge positions and lower mark-to-market earnings, partially offset by:

•

Increased operating income at Field Services, due to the favorable effects of commodity prices, net of hedging, and improved results from Duke Energy Field Services LLC’s (DEFS’) trading and marketing activities, and

•

Increased operating income at Crescent, due to the sale of a commercial project and the Alexandria land tract in the Washington, D.C. area, increased “legacy” land sales and increased residential developed lot sales.

For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses

Other Income and Expenses decreased $169 million for the three months and $194 million for the six months ended June 30, 2004, compared to the same periods in 2003, due primarily to a $175 million gain in the second quarter of 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel and gains of $31 million on the sales of Natural Gas Transmission’s interests in Alliance Pipeline and the associated Aux Sable liquids plant in the second quarter of 2003.

Segment Results

Beginning in 2004, Crescent, formerly part of Other Operations, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages “legacy” land holdings, primarily in the southeastern and southwestern United States. All other entities previously part of Other Operations and now within Other still remain, primarily: DukeNet Communications LLC and Duke Capital’s 50% equity investment in Duke/Fluor Daniel (D/FD). Unallocated corporate costs are also recorded in Other in the following table.

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 and cash equivalents are managed centrally by Duke Capital, so the gains and losses on foreign currency remeasurement associated with cash balances, and interest income on those balances, are generally 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 EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

EBIT by Business Segment (in millions)


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Natural Gas Transmission	$	311		$	306		$	709		$	729
Field Services		94			53			186			83
Duke Energy North America		(39	)		211			(596	)		234
International Energy		68			91			97			131
Crescent		87			21			147			21

Total reportable segment EBIT		521			682			543			1,198
Other		30			(1	)		57			52
Interest expense		(263	)		(255	)		(536	)		(520	)
Minority interest expense and other ^a		43			(3	)		53			(1	)

Consolidated earnings from continuing operations before income taxes	$	331		$	423		$	117		$	729

^a	Includes interest income, foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

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,
(in millions, except where noted)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	688	$	692	$	(4	)	$	1,726	$	1,660	$	66
Operating expenses		397		421		(24	)		1,035		988		47
Gains on sales of other assets, net		9		—		9			9		1		8

Operating income		300		271		29			700		673		27
Other income, net of expenses		13		45		(32	)		19		79		(60	)
Minority interest expense		2		10		(8	)		10		23		(13	)

EBIT	$	311	$	306	$	5		$	709	$	729	$	(20	)

Proportional throughput, TBtu ^a		726		742		(16	)		1,815		1,824		(9	)

^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, 2004 as Compared to June 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $22 million decrease as a result of the sale of Pacific Northern Gas Limited (PNG) in December 2003

•

A $20 million decrease in gas distribution revenues, due primarily to reduced volumes

•

A $13 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 due to improved operational results

•

A $10 million increase from completed and operational business expansion projects in the United States.

Operating Expenses. The decrease was driven primarily by:

•

A $20 million decrease as a result of operations sold in 2003

•

An $18 million decrease in gas purchases for distribution, due primarily to reduced volumes

•

A $17 million decrease related to the 2004 resolution of ad valorem tax adjustments in various states, partly offset by the resolution of contingency items of $5 million in the second quarter of 2003

•

A $10 million increase caused by foreign exchange impacts.

Other Income, net of expenses. The decrease was driven primarily by gains of $31 million on the sales of Natural Gas Transmission’s interests in Alliance Pipeline and the associated Aux Sable liquids plant in April 2003.

EBIT. EBIT increased primarily as a result of contributions from improved operational results, U.S. business expansions, and foreign exchange EBIT impacts from the strengthening Canadian currency, partially offset by gains from sales of equity investments (included in other income) recorded in the prior year second quarter and forgone earnings from various equity investments sold during 2003.

Six Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $104 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 $27 million increase due to improved operational results

•

A $21 million increase from completed and operational business expansion projects in the United States

•

A $53 million decrease as a result of the sale of Empire State Pipeline in February 2003 and of PNG in December 2003

•

A $40 million decrease in gas distribution revenues, resulting from lower volumes partly offset by higher commodity costs that are passed through to customers without mark-up.

Operating Expenses. The increase was driven primarily by:

•

A $75 million increase caused by foreign exchange impacts

•

An $8 million increase associated with the business expansion projects placed in service

•

Cost increases of $18 million, including depreciation and processing plant maintenance activity in Canada

•

A $30 million decrease in gas purchases for distribution, due primarily to reduced volumes partly offset by higher commodity costs

•

A $44 million decrease as a result of operations sold in 2003

•

A $17 million decrease related to the 2004 resolution of ad valorem tax adjustments in various states, offset by the resolution of various contingencies of $25 million in the 2003 period.

Other Income, net of expenses. The decrease was driven primarily by:

•

A $15 million decrease in equity earnings as a result of investments sold in 2003

•

A $47 million decrease as a result of prior year gains on sales, primarily the gain on the sale of Natural Gas Transmission’s interests in Northern Border Partners L.P. in January 2003 and in Alliance Pipeline and the Aux Sable liquids plant in April 2003.

Minority Interest Expenses. The decrease was driven primarily by the sale of PNG in 2003.

EBIT. EBIT decreased primarily as a result of gains from sales of equity investments (included in other income) recorded in the prior year and forgone earnings from various equity investments sold during 2003. Those decreases were partially offset by contributions from improved operational results, U.S. business expansions, and foreign exchange EBIT impacts from the strengthening Canadian currency.

Field Services


	Three Months Ended June 30,							Six Months Ended June 30,
(in millions, except where noted)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	2,356	$	2,048	$	308		$	4,731	$	4,598	$	133
Operating expenses		2,225		1,991		234			4,474		4,500		(26	)

Operating income		131		57		74			257		98		159
Other income, net of expenses		15		24		(9	)		33		39		(6	)
Minority interest expense		52		28		24			104		54		50

EBIT	$	94	$	53	$	41		$	186	$	83	$	103

Natural gas gathered and processed/transported, TBtu/d^a		7.5		7.6		(0.1	)		7.4		7.6		(0.2	)
NGL production, MBbl/d^b		371		352		19			364		360		4
Average natural gas price per MMBtu ^{c, d, e}	$	5.99	$	5.41	$	0.58		$	5.84	$	6.00		($0.16	)
Average NGL price per gallon ^{d, e}	$	0.61	$	0.49	$	0.12		$	0.60	$	0.54	$	0.06

^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, 2004 as Compared to June 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $175 million increase due to higher average NGL prices

•

A $125 million increase due to higher average natural gas prices

•

A $35 million increase related to the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips during the three months ended June 30, 2004

•

A $30 million decrease primarily related to lower wholesale propane marketing activity partially offset by higher NGL sales volumes

•

A $5 million increase from higher processed volumes resulting from favorable processing economics. Overall, throughput decreased due primarily to slightly lower gathering and transportation volumes.

•

A $5 million decrease related to cash flow hedging, which reduced revenues by approximately $50 million for the three months ended June 30, 2004 and by $45 million for the three months ended June 30, 2003.

Operating Expenses. The increase was driven primarily by:

•

A $240 million increase due to higher average costs of raw natural gas supply

•

A $25 million decrease from lower processed raw natural gas supply volume and lower wholesale propane marketing activity

•

A $30 million increase related to the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips during the three months ended June 30, 2004

•

A $5 million decrease in operating, and general and administrative expenses, due to lower repairs, maintenance, environmental and labor and benefits.

Minority Interest Expense. Minority interest expense increased due to increased earnings from DEFS, Duke Capital’s joint venture with ConocoPhillips. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT resulted primarily from the favorable effects of commodity prices. The full impact from the effects of commodity prices were not realized as some of DEFS’ sales volumes were previously hedged at prices different than actual market prices.

Six Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $190 million increase due to higher average NGL prices

•

A $120 million decrease from lower throughput related to reduced raw natural gas supply volume, due to reservoir decline exceeding supply from new drilling activity and increased plant downtime due to maintenance

•

A $60 million decrease due to lower average natural gas prices

•

A $35 million increase related to the acquisition of gathering processing and transmission assets in southeast New Mexico from ConocoPhillips during the six months ended June 30, 2004

•

A $35 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing

•

A $25 million increase related to cash flow hedging, which reduced revenues by approximately $95 million for the six months ended June 30, 2004 and by $120 million for the six months ended June 30, 2003

•

A $20 million increase related to higher NGL sales volumes.

Operating Expenses. The decrease was driven primarily by:

•

A $90 million decrease from lower processed raw natural gas supply volume

•

A $55 million increase due to higher average costs of raw natural gas supply which is primarily due to an increase in average NGL prices partially offset by a decrease in average natural gas prices

•

A $30 million increase related to the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips during the six months ended June 30, 2004

•

A $15 million decrease in operating, and general and administrative expenses, due to lower repairs, maintenance, environmental and labor and benefits expenses.

Minority Interest Expense. Minority interest expense increased due to increased earnings from DEFS. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT primarily resulted from the favorable effects of commodity prices and improved results from trading and marketing activities. The full impact from the effects of commodity prices were not realized as some of DEFS’ sales volumes were previously hedged at prices different than actual market prices.

Duke Energy North America ^a


	Three Months Ended June 30,									Six Months Ended June 30,
(in millions, except where noted)	2004			2003			Increase (Decrease)			2004			2003			Increase (Decrease)
Operating revenues	$	672		$	962		$	(290	)	$	1,328		$	2,358		$	(1,030	)
Operating expenses		705			945			(240	)		1,576			2,327			(751	)
Losses on sales of other assets, net		(16	)		—			(16	)		(368	)		—			(368	)
Operating (loss) income		(49	)		17			(66	)		(616	)		31			(647	)
Other income, net of expenses		3			187			(184	)		(1	)		196			(197	)
Minority interest benefit		(7	)		(7	)		—			(21	)		(7	)		(14	)

EBIT	$	(39	)	$	211		$	(250	)	$	(596	)	$	234		$	(830	)

Actual plant production, GWh ^{b, c}		5,895			4,510			1,385			11,356			9,620			1,736
Proportional megawatt capacity in operation											15,660			15,206			454

^a	See Note 1 to the Consolidated Financial Statements regarding the revision for Duke Energy Fuels

^b	Gigawatt-hours

^c	Includes plant production from plants accounted for under the equity method

Three Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $359 million decrease from lower natural gas sales volumes, due primarily to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $32 million from higher average natural gas prices realized in the current quarter. The second quarter of 2004 experienced relatively high volatility in gas prices, which has been a market trend since the latter part of 2003.

•

$63 million in lower net trading margins, due primarily to the continued wind down of DETM’s operations, including the absence of 2003 positive net trading margins. DENA recognized approximately $22 million in net mark-to-market gains incurred primarily from undesignated power and gas hedges, which resulted in an offsetting increase of $14 million over prior quarter.

•

A $112 million increase from higher power generation volumes, due primarily to two plants entering into commercial operation late in the second quarter of 2003; overall higher plant run-times in the western region as a result of higher average spark spreads; and consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method. Offsetting this increase was an approximate $22 million decrease in revenues from lower average realized power prices, primarily as a result of the recognition of losses related to certain DENA power sales contracts. The unrealized power sales losses will continue to be recognized as the underlying contracts settle through 2015, and accordingly, will continue to impact DENA’s results of operations.

Operating Expenses. The decrease was driven primarily by:

•

A $379 million decrease from lower natural gas purchase volumes, due primarily to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $19 million from higher average natural gas prices realized in the current quarter. The second quarter of 2004 experienced relatively high volatility in gas prices, which has been a market trend since the latter part of 2003.

•

A $113 million ($108 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceeding in April 2004 (see Note 12 to the Consolidated Financial Statements).

•

$25 million in lower depreciation expense, primarily from the reduction in plant cost basis as a result of plant impairment charges taken in the fourth quarter of 2003, and discontinuing

depreciation related to the southeast region plants which were classified as “assets held for sale” in March 2004. Offsetting this decrease was $6 million of higher depreciation due to two plants entering into commercial operation late in the second quarter of 2003 and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method.

•

$17 million in lower general and administrative expenses, primarily from the impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower bad debt expense.

•

$139 million of higher plant fuel costs, due to overall higher average realized natural gas prices in the current quarter, due primarily to lower value recognized from financial gas hedges. The unrealized gains from the financial gas hedges will continue to be recognized as the underlying contracts settle through 2017, and accordingly, will continue to impact DENA’s results of operations. Additionally, there was an approximate $15 million increase in plant fuel costs due primarily to two plants entering into commercial operation late in the second quarter of 2003; overall higher plant run-times in the Western region as a result of higher average spark spreads; and the consolidation of a partial interest in one of DENA’s Canadian power facilities beginning in 2004, which was previously accounted for under the equity method.

•

A $105 million increase in operating expenses from a charge related to the California and western U.S. energy markets settlement in June 2004 (see Note 12 to the Consolidated Financial Statements).

•

An $11 million increase in operations and maintenance expense, due primarily to two plants entering into commercial operation late in the second quarter of 2003 and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method.

Losses on Sales of Other Assets, net. Losses in 2004 were $16 million ($10 million net of minority interest expense) due to the liquidation of contractual positions in connection with the continued wind down of DETM’s operations.

Other Income, net of expenses. The decrease in other income, net of expenses was due primarily to a $175 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel.

EBIT. The decrease in EBIT was due primarily to the $175 million gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel and an $80 million decrease in total gross margin from lower net sales, lower values realized from hedge positions, and lower mark-to-market earnings as outlined above.

Six Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $752 million decrease from lower natural gas sales volumes, due primarily to the continued wind down of DETM’s operations. Overall higher average year-to-date gas prices in 2003 versus 2004 contributed another approximate $157 million decrease in natural gas sales realized.

•

$115 million in lower net trading margins, due to the continued wind down of DETM’s operations, including the absence of 2003 positive net trading margins and $56 million in net mark-to-market losses incurred from undesignated power and gas hedge positions.

•

A $191 million increase from higher power generation volumes, due primarily to two plants entering into commercial operation late in the second quarter of 2003; overall higher plant run-times in the Western region as a result of higher average spark spreads; and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method. Offsetting this increase was an approximate $142 million decrease in revenues from lower average realized power prices, primarily as a result of the recognition of losses related to certain DENA power sales contracts. The unrealized power sales losses will continue to be recognized as the underlying contracts settle through 2015, and accordingly, will continue to impact DENA’s results of operations.

Operating Expenses. The decrease was driven primarily by:

•

A $768 million decrease from lower natural gas purchase volumes, due primarily to the continued wind down of DETM’s operations. Overall higher average year-to-date gas prices in 2003 versus 2004 contributed another approximate $157 million decrease in natural gas purchase costs.

•

A $113 million ($108 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceedings in April 2004 (see Note 12 to the Consolidated Financial Statements).

•

$41 million of lower depreciation expense, primarily from the reduction in plant cost basis as a result of plant impairment charges taken in the fourth quarter of 2003 and discontinuing depreciation related to the southeast region plants which were classified as “assets held for sale” in March 2004. Offsetting this decrease was $16 million of higher depreciation due to two plants entering into commercial operation late in the second quarter of 2003 and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method.

•

$21 million of lower general and administrative expenses, primarily from the impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower bad debt expense.

•

$143 million of higher plant fuel costs due to overall higher average realized natural gas prices in the current year, due primarily to lower value recognized from financial gas hedges. The unrealized gains from the financial gas hedges will continue to be recognized as the underlying contracts settle through 2017, and accordingly, will continue to impact DENA’s results of operations. Additionally, there was an approximate $60 million increase in plant fuel costs due to two plants entering into commercial operation late in the second quarter of 2003; overall higher plant run-times in the Western region as a result of higher average spark spreads; and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method.

•

A $105 million increase in operating expenses from a charge related to the California and western U.S. energy markets settlement in June 2004 (see Note 12 to the Consolidated Financial Statements).

•

A $23 million increase in operations and maintenance expense, due primarily to two plants entering into commercial operation late in the second quarter of 2003 and the 2004 consolidation of a partial interest in one of DENA’s Canadian power facilities, which was previously accounted for under the equity method.

Losses on Sales of Other Assets, net. Losses on sales of other assets for the six months ended June 30, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the announced sale of DENA’s southeastern plants. (See Note 8 to the Consolidated Financial Statements.)

Other Income, net of expenses. The decrease in other income, net of expenses was due primarily to the $175 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel and current year foreign currency remeasurement losses associated with DENA’s Canadian business activity.

Minority Interest Benefit. Minority interest benefit increased due primarily to increased DETM losses in 2004 from the continued wind down of its operations.

EBIT. The decrease in EBIT was due primarily to the $360 million pre-tax loss on the sale of the southeast plants, a $175 million pre-tax gain in 2003 from the announced sale of DENA’s 50% interest in Duke/UAE Ref-Fuel and a $309 million decrease in total gross margin from lower net sales, lower values realized from hedge positions, and lower mark-to-market earnings as outlined above.

International Energy


	Three Months Ended June 30,							Six Months Ended June 30,
(in millions, except where noted)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	147	$	169	$	(22	)	$	301	$	341	$	(40	)
Operating expenses		98		90		8			229		225		4
Gains on sales of other assets, net		—		1		(1	)		—		1		(1	)

Operating income		49		80		(31	)		72		117		(45	)
Other income, net of expenses		22		15		7			31		22		9
Minority interest expense		3		4		(1	)		6		8		(2	)

EBIT	$	68	$	91	$	(23	)	$	97	$	131	$	(34	)

Sales, GWh		4,248		4,446		(198	)		8,811		8,416		395
Proportional megawatt capacity in operation									4,130		4,013		117

Three Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $13 million decrease in revenues in Guatemala and El Salvador, due to unfavorable market conditions

•

An $11 million decrease due to adjustments in the second quarter of 2003 as a result of a regulatory audit in Brazil

Operating Expenses. The increase was driven primarily by:

•

An $18 million increase due to a reserve reversal in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business

•

An $8 million increase due to adjustments in the second quarter of 2003 as a result of a regulatory audit in Brazil

•

A $12 million decrease in spot market purchases in Guatemala and El Salvador, due to unfavorable market conditions

•

A $10 million decrease due to a change in the method of revenue recognition in Peru to reflect a netting of volumes transferred to/from the electricity grid in 2003, which is offset in operating revenues

•

A $6 million decrease due to a reduction in bad debt expense.

EBIT. The decrease in EBIT was due primarily to adjustments of $19 million in the second quarter of 2003 as a result of a regulatory audit in Brazil and an $18 million reserve reversal in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business.

Six Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $33 million decrease in natural gas sales, due to the termination of a natural gas sales contract from the liquefied natural gas business

•

A $23 million decrease in revenues in Guatemala and El Salvador, due to unfavorable market conditions

•

An $11 million decrease due to adjustments in the second quarter of 2003 as a result of a regulatory audit in Brazil

•

A $14 million increase which is equally attributed to higher sales prices and volumes realized from the initial contracts in Brazil

•

A $12 million increase due to the commencement of operations at Planta Arizona in Guatemala.

Operating Expenses. The increase was driven primarily by:

•

An $18 million increase due to a reserve reversal in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business

•

A $13 million charge associated with the planned disposition of the ownership share in the Cantarell nitrogen facility in Mexico

•

A $13 million increase due partially to the commencement of operations at Planta Arizona in Guatemala, and partially to increased energy purchases and transmission fees in Brazil

•

An $11 million increase in administrative and general expenses

•

An $8 million increase due to adjustments in the second quarter of 2003 as a result of a regulatory audit in Brazil

•

A $34 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the liquefied natural gas business

•

A $21 million decrease in spot market purchases in Guatemala and El Salvador, due to unfavorable market conditions.

EBIT. The decrease in EBIT was due primarily to adjustments of $19 million as a result of the regulatory audit in Brazil in 2003, a $17 million decrease due to the termination of a natural gas sales contract from the liquefied natural gas business, a $13 million charge associated with the planned disposition of the ownership share in the Cantarell facility, an $11 million increase in administrative and general expenses, an $11 million increase included in other income due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment, and a $10 million increase due to Planta Arizona operations in Guatemala and favorable prices in Peru.

Crescent


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2004		2003		Increase (Decrease)		2004		2003		Increase (Decrease)
Operating revenues	$	101	$	76	$	25	$	140	$	97	$	43
Operating expenses		75		63		12		112		86		26
Gains on sales of investments in commercial and multi-family real estate		62		9		53		121		11		110

Operating income		88		22		66		149		22		127
Minority interest expense		1		1		—		2		1		1

EBIT	$	87	$	21	$	66	$	147	$	21	$	126

Three Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The increase was driven primarily by a $27 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina and the LandMar division in northeastern Florida, offset by decreased sales at the Twin Creeks project near Austin, Texas as a result of a large bulk sale of lots in the second quarter of 2003.

Operating Expenses. The increase was driven primarily by a $20 million increase in the cost of residential developed lot sales, due to increased sales at the projects noted above, offset by a $10 million decrease due to the contribution of a conservation easement and related write-off of land basis in April 2003.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by a $49 million increase in real estate land sales due primarily to the sale of the Alexandria land tract in the Washington, D.C. area in June 2004.

EBIT. As discussed above, the increase in EBIT was driven primarily by the sale of the Alexandria land tract in the Washington, D.C. area and an increase in residential developed lot sales.

Six Months Ended June 30, 2004 as Compared to June 30, 2003

Operating Revenues. The increase was driven primarily by a $45 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina, the LandMar division in northeastern Florida and the Lake Keowee projects in northwestern South Carolina, offset by decreased developed lot sales at the Twin Creeks project near Austin, Texas as a result of the large bulk sale of lots in the second quarter of 2003.

Operating Expenses. The increase was driven primarily by a $31 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above.

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

•

A $20 million increase in commercial project sales, due to the sale of a commercial project in the Washington, D.C. area in March 2004 compared to no commercial project sales in the first six months of 2003

•

A $49 million increase in real estate land sales due primarily to the sale of the Alexandria land tract in the Washington, D.C. area in June 2004

•

A $42 million increase in land management or “legacy” land sales, due to several large sales closed in the first quarter of 2004

EBIT. As discussed above, the increase in EBIT was driven primarily by sales of a commercial project and the Alexandria land tract in the Washington, D.C. area, an increase in “legacy” land sales and an increase in residential developed lot sales.

Other

EBIT for Other increased $31 million for the three months and was basically flat for the six months ended June 30, 2004, compared to the same periods in 2003. The three month increase was due primarily to higher D/FD profits resulting from profit eliminations in Other in the prior year not occurring in 2004, as a result of the wind down of D/FD.

Other Impacts on Net Income

Income tax expense from continuing operations decreased 46% for the three months and 93% for the six months ended June 30, 2004, compared to the same periods in 2003. The decrease was due primarily to the release of income tax reserves of approximately $45 million, resulting from the resolution of various outstanding income tax issues in the second quarter of 2004 and changes in estimates. Also contributing to the tax decreases were decreases in earnings from continuing operations before income taxes of 22% for the three months and 84% for the six months ended June 30, 2004.

Income from discontinued operations for the three months ended June 30, 2004 was flat, compared to the same period in 2003. The increase in income from discontinued operations for the six months ended June 30, 2004 was due primarily to a $268 million after-tax gain in 2004 surrounding the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business and its European operations. (See Note 8 to the Consolidated Financial Statements.)

During 2003, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $133 million. The change in accounting principles included an after-tax and minority interest charge of $123 million related to the implementation of Emerging Issues Task Force (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,” and an after-tax charge of $10 million related to the implementation of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.”

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities increased $510 million for the six months ended June 30, 2004, compared to the same period in 2003, due primarily to higher cash settlements from trading and marketing activities and changes in working capital in the 2004 period. Cash flow from changes in working capital for the 2004 period was higher than the 2003 period due primarily to the liquidation of inventory in 2004 at DENA and Natural Gas Transmission, net of higher receivables balances driven by higher NGL and gas prices at Field Services.

Investing Cash Flows

Net cash provided by investing activities increased $29 million for the six months ended June 30, 2004, compared to the same period in 2003. Of this increase in cash provided, $319 million relates to decreased capital and investment expenditures due largely to continued lower investments in generating facilities at DENA offset by an increase in investments in real estate at Crescent and $256 million relates to an increase in proceeds from the sales of commercial and multi-family real estate at Crescent due primarily to sales of the Potomac Yard retail center and the Alexandria land tract in the Washington, D.C. area in the 2004 period. These increases were offset by $509 million related to decreased net proceeds from the sales of equity investments and other assets due primarily to sales in the 2003 period of DENA’s 50% ownership

interest in American Ref Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline and its investment in the Alliance Pipeline; Field Services’ sale of assets to Crosstex & Scissortail; Duke Capital’s sale of the TEPPCO class B units and the monetization of various investments at DCP, which were partially offset by the sale of International Energy’s Asia-Pacific power generation and natural gas transmission businesses in the 2004 period.

Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $466 million for the six months ended June 30, 2004, compared to the same period in 2003. This change was due primarily to approximately $1.3 billion higher cash redemptions of long term debt and net paydowns of notes and commercial paper in 2003 as compared to 2004. Partially offsetting this change were capital contributions from parent of approximately $800 million for six months ended June 2003. Total debt reductions of approximately $1.2 billion in 2004 consisted of approximately $315 million in net cash redemptions, approximately $50 million of Australian debt held in trust and fully funded, and approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific operations. The $840 million does not include the approximately $50 million of Australian debt which has been placed in trust and fully funded in connection with the closing of the sale transaction and will be repaid in September 2004. This trust is included in the Consolidated Financial Statements as Duke Capital is the primary beneficiary of the trust and, therefore, is required to consolidate the trust under provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities.”

Duke Capital’s cash requirements for 2004 are expected to be funded by cash from operations and the sale of non-strategic assets, which are expected to be adequate for funding capital expenditures and planned debt reductions.

Significant Financing Activities. For discussion of Duke Capital’s significant financing activities, see Note 4 to the Consolidated Financial Statements.

Additionally, on June 1, 2004, Westcoast Energy, Inc. redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.

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, 2004, 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 have not changed since March 1, 2004 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/A for December 31, 2003. The outlook for DETM was changed from Negative Outlook to Stable on July 9, 2004. The following table summarizes the August 1, 2004 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.


Credit Ratings Summary as of August 1, 2004
	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. ^a	BBB	Not applicable	A(low)
Union Gas Limited ^a	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC ^b	A	A1	A
Maritimes & Northeast Pipeline, LP ^b	A	A1	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

Duke Capital’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors, Duke Capital is unable to execute its business plan, or if its earnings outlook materially deteriorates, Duke Capital’s ratings could be further affected.

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 transacts business through DETM or Duke Energy Marketing America, a wholly owned subsidiary of Duke Capital.

A reduction in the credit rating of Duke Capital to below investment grade as of June 30, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $360 million, compared to $510 million as of December 31, 2003. The other potential collateral posting requirements 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/A for December 31, 2003 – Financing Cash Flows and Liquidity have not materially changed as of June 30, 2004. As a result, the total potential collateral requirement, including additional collateral, cash segregation and settlement payments, has declined since December 31, 2003.

Other Financing Matters. As of June 30, 2004, Duke Capital and its subsidiaries had effective Securities and Exchange Commission shelf registrations for up to $1,500 million in gross proceeds from debt and other securities. This represents an increase of approximately $500 million as compared to December 31, 2003, providing future funding flexibility. Not included in this total is $750 million in shelf capacity reserved for the remarketing of the Duke Capital 4.32% senior notes, due 2006, underlying the Duke Energy’s 8% Equity Units, Series B. Additionally, as of June 30, 2004, Duke Capital had access to 900 million Canadian dollars (U.S. $669 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. 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/A for December 31, 2003.

CURRENT ISSUES

For information on current issues related to Duke Capital, see the following Notes to the Consolidated Financial Statements: Note 11, Regulatory Matters, and Note 12, Commitments and Contingencies.

New Accounting Standards

The following new accounting standard has been issued, but has not yet been fully adopted by Duke Capital as of June 30, 2004:

•

The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used

•

The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate

•

The current best estimate of the range of contributions expected to be made in the following year

•

The accumulated benefit obligation for defined-benefit pension plans

•

Disclosure of the measurement date utilized.

Subsequent Events

In July 2004, Duke Energy reached an agreement in principle to settle the Federal Energy Regulatory Commission refund proceedings and other significant litigation related to the western energy markets during 2000-2001. For information related to this agreement, see Note 12 to the Consolidated Financial Statements.

On May 4, 2004 Duke Capital announced the sale of its merchant generation business in the southeastern United States to KGen Partners LLC (KGen). The sale transaction has obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a cumulative pre-tax loss of approximately $367 million, of which approximately $360 million was recognized in the first quarter of 2004 to reduce the carrying value of those assets to their estimated fair values, while the remaining amount of the loss will be recognized by Duke Capital in the third quarter of 2004. Subsequent to the closing of the transaction, DENA will continue to provide certain transitional services and operating and maintenance services for the sold assets, including potential exercise of limited plant dispatch rights for a period not to exceed six months from August 5, 2004. DENA anticipates recognizing the sale transaction in the third quarter of 2004 pending resolution of certain continuing involvement provisions.

For information on subsequent events related to debt and credit facilities, see Note 4 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/A for December 31, 2003.

Commodity Price Risk

Normal Purchases and Normal Sales. The unrealized loss associated with power forward sales contracts designated under the normal purchases and normal sales exemption was approximately $915 million as of June 30, 2004 and $700 million as of December 31, 2003. This unrealized loss represents the difference between the normal purchases and normal sales contract prices and the forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $605 million as of June 30, 2004 and $400 million as December 31, 2003, which are recorded on the Consolidated Balance Sheets in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. Duke Capital intends to fulfill those contractual obligations with production from its power generation fleet and, assuming that occurs, the above unrealized gains and losses would not be recognized in DENA’s EBIT.

Trading and Undesignated Contracts. The risk in the mark-to-market (MTM) portfolio is measured and monitored on a daily basis using 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, including limits on the nominal size of positions, are also used to limit and monitor risk in the trading portfolio on monthly and annual bases.

DER computations are based on historical simulation. Duke uses price movements over the most recent 11-day period, which it considers 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 price movements and a one-day holding period specified for the calculation. Duke Capital’s DER amounts for commodity derivatives recorded using the MTM accounting method are shown in the following table.

Daily Earnings at Risk (in millions)


	June 30, 2004 One-Day Impact on Operating Income for 2004^a		Estimated Average One- Day Impact on Operating Income for 2^ndQuarter 2004 ^a		Estimated Average One- Day Impact on Operating Income for the Year 2003 ^a		High One-Day Impact on Operating Income for 2^ndQuarter 2004 ^a		Low One-Day Impact on Operating Income for 2^nd Quarter 2004 ^a
Calculated DER	$	11	$	16	$	6	$	30	$	8

^a	DER measures the MTM 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, is not material.

Item 4.

Controls and Procedures.

Duke Capital’s management, including the Chief Executive Officer 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)) (Disclosure Controls Evaluation) 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 the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

As disclosed in Duke Capital’s 2003 Annual Report on Form 10-K/A, Duke Capital’s independent registered public accounting firm, Deloitte & Touche LLP (Deloitte), noted certain matters involving Duke Capital’s internal controls that it considered to be a reportable condition under the standards established by the Public Company Accounting Oversight Board (United States). The reportable condition was not considered by Deloitte to be a material weakness under the applicable auditing standards and had no material affect on Duke Capital’s financial statements. Management continues to implement procedures and controls to address the identified conditions and enhance the reliability of Duke Capital’s internal control procedures.

Management has concluded that the Disclosure Controls Evaluation identified no changes in Duke Capital’s internal control over financial reporting that occurred during the second quarter of 2004 that have materially affected, or are reasonably likely to materially affect, Duke Capital’s internal control over financial reporting.

As disclosed in the Notes to the Consolidated Financial Statements in Duke Capital’s 2003 Annual Report on Form 10-K/A and March 31, 2004 Quarterly Report on Form 10-Q/A, in 2004 Duke Capital elected to change its business segments to present Crescent Resources, LLC as a separate segment. In connection with this change, management determined that revisions were required to the presentation of the Consolidated Statements of Cash Flows, Statements of Operations and Balance Sheets related to its real estate activities. Management evaluated such revision and determined that while this represents a significant deficiency, it is not a material weakness and that its disclosure controls are effective.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

For additional information concerning litigation and other contingencies, see Note 12 to the Consolidated Financial Statements, “Commitments and Contingencies;” and Item 3, “Legal Proceedings,” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” in Duke Capital’s Annual Report on Form 10-K/A for December 31, 2003, which are incorporated herein by reference.

Item 6.

Exhibits and Reports on Form 8-K.

(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

10-1		$600,000,000 364-Day Credit Agreement dated as of June 30, 2004, among Duke Capital LLC, the Banks listed therein and JPMorgan Chase Bank, as Administrative Agent (filed with the Quarterly Report on Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2004, File No. 1-4928, as Exhibit 10-1).

10-2		$600,000,000 Three-Year Credit Agreement dated as of June 30, 2004, among Duke Capital LLC, the Banks listed therein and JPMorgan Chase Bank, as Administrative Agent (filed with the Quarterly Report on Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2004, File No. 1-4928, as Exhibit 10-2).

*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.

(b)	Reports on Form 8-K

Duke Capital filed no reports on Form 8-K during the second quarter of 2004.

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 13, 2004				/S/ DAVID L. HAUSER
				David L. Hauser
				President

Date: August 13, 2004				/S/ KEITH G. BUTLER
				Keith G. Butler
				Chief Financial Officer and Controller