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 September 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 SEPTEMBER 30, 2004

INDEX


Item		Page
PART I. FINANCIAL INFORMATION

1.	Financial Statements	1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2003, as revised	1
	Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	2
	Consolidated Statements of Cash Flows for the Nine Months Ended September 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	38
3.	Quantitative and Qualitative Disclosures about Market Risk	58
4.	Controls and Procedures	59

PART II. OTHER INFORMATION

1.	Legal Proceedings	60
6.	Exhibits	61
	Signatures	62

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 the areas served by Duke Capital

•

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

•

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, liquified natural gas, 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 September 30,						Nine Months Ended September 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		$	3,366		$	9,577		$	10,116
Regulated natural gas		585			590			2,202			2,105

Total operating revenues		3,844			3,956			11,779			12,221

Operating Expenses
Natural gas and petroleum products purchased		2,360			2,458			7,361			7,839
Operation, maintenance and other		456			585			1,416			1,487
Depreciation and amortization		250			264			747			773
Fuel used in electric generation and purchased power		229			368			731			721
Property and other taxes		62			49			193			184
Impairment and other related charges		22			—			25			—
Impairment of goodwill		—			254			—			254

Total operating expenses		3,379			3,978			10,473			11,258

Gains on Sales of Investments in Commercial and Multi-Family Real Estate		28			36			149			47
Losses on Sales of Other Assets, net		(2	)		(80	)		(367	)		(78	)

Operating Income (Loss)		491			(66	)		1,088			932

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		35			35			111			86
(Losses) gains on sales and impairments of equity investments		(14	)		33			(14	)		266
Other income and expenses, net		39			26			101			73

Total other income and expenses		60			94			198			425

Interest Expense		273			277			808			797
Minority Interest Expense (Benefit)		61			(11	)		142			68

Earnings (Loss) From Continuing Operations Before Income Taxes		217			(238	)		336			492
Income Tax Expense (Benefit)		1,215			(111	)		1,233			137

(Loss) Income From Continuing Operations		(998	)		(127	)		(897	)		355
Discontinued Operations
Net operating (loss) income, net of tax		(11	)		(13	)		(8	)		4
Net (loss) gain on dispositions, net of tax		(1	)		36			268			47

(Loss) Income From Discontinued Operations		(12	)		23			260			51

(Loss) Income Before Cumulative Effect of Change in Accounting Principle		(1,010	)		(104	)		(637	)		406
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			—			—			(133	)

Net (Loss) Income	$	(1,010	)	$	(104	)	$	(637	)	$	273

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	September 30, 2004		December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	2,802	$	986
Receivables (net of allowance for doubtful accounts of $209 at September 30, 2004 and $236 at December 31, 2003)		2,195		2,484
Inventory		499		483
Assets held for sale		125		424
Unrealized gains on mark-to-market and hedging transactions		1,135		1,472
Other		483		467

Total current assets		7,239		6,316

Investments and Other Assets
Investments in unconsolidated affiliates		1,294		1,380
Goodwill		4,002		3,962
Notes receivable		225		260
Unrealized gains on mark-to-market and hedging transactions		1,646		1,815
Assets held for sale		236		1,444
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $24 at September 30, 2004 and $32 at December 31, 2003)		1,280		1,331
Other		901		1,336

Total investments and other assets		9,584		11,528

Property, Plant and Equipment
Cost		25,279		25,660
Less accumulated depreciation and amortization		5,206		4,457

Net property, plant and equipment		20,073		21,203

Regulatory Assets and Deferred Debits		1,114		1,060

Total Assets	$	38,010	$	40,107

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	September 30, 2004		December 31, 2003
LIABILITIES AND MEMBER’S/STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	1,475	$	2,018
Notes payable and commercial paper		41		52
Taxes accrued		620		—
Interest accrued		222		229
Liabilities associated with assets held for sale		41		651
Current maturities of long-term debt		3,068		1,192
Unrealized losses on mark-to-market and hedging transactions		964		1,185
Other		1,375		1,425

Total current liabilities		7,806		6,752

Long-term Debt, including debt to an affiliate of $258 at December 31, 2003		11,182		13,652

Deferred Credits and Other Liabilities
Deferred income taxes		3,505		2,360
Unrealized losses on mark-to-market and hedging transactions		1,225		1,698
Liabilities associated with assets held for sale		14		737
Other		1,109		1,159

Total deferred credits and other liabilities		5,853		5,954

Commitments and Contingencies

Minority Interests		1,587		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		10,797		—
Accumulated other comprehensive income		785		600

Total member’s/common stockholder’s equity		11,582		12,048

Total Liabilities and Member’s/Stockholder’s Equity	$	38,010	$	40,107

See Notes to Consolidated Financial Statements.

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Nine Months Ended September 30,
	2004			2003
				(as Revised - see Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(637	)	$	273
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation and amortization		768			773
Cumulative effect of change in accounting principle		—			133
Gains on sales of investments in commercial and multi-family real estate		(149	)		(47	)
Losses (gains) on sales of equity investments and other assets and impairment charges		131			(188	)
Impairment of goodwill		—			254
Deferred income taxes		1,062			134
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		195			18
Receivables		343			1,400
Inventory		(8	)		(136	)
Other current assets		72			(59	)
Increase (decrease) in
Accounts payable		(635	)		(1,232	)
Taxes accrued		551			202
Other current liabilities		65			(267	)
Capital expenditures for residential real estate		(218	)		(136	)
Cost of residential real estate sold		127			78
Other, assets		149			16
Other, liabilities		153			75

Net cash provided by operating activities		1,969			1,291

CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net of refund		(738	)		(1,137	)
Net proceeds from the sale of equity investments and other assets, and sales of and collections on notes receivable		1,199			1,459
Proceeds from the sales of commercial and multi-family real estate		413			95
Other		(70	)		(16	)

Net cash provided by investing activities		804			401

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt		166			275
Payments for the redemption of
Long-term debt		(929	)		(1,401	)
Guaranteed preferred beneficial interests in subordinated notes		—			(250	)
Preferred stock of a subsidiary		(76	)		(38	)
Notes payable and commercial paper		(22	)		(838	)
Distributions to minority interests		(1,094	)		(2,067	)
Contributions from minority interests		959			1,958
Capital contributions from parent		—			1,050
Other		1			(3	)

Net cash used in financing activities		(995	)		(1,314	)

Changes in cash and cash equivalents associated with assets held for sale		38			—

Net increase in cash and cash equivalents		1,816			378
Cash and cash equivalents at beginning of period		986			831

Cash and cash equivalents at end of period	$	2,802		$	1,209

Supplemental Disclosures
Significant non-cash transactions:
Debt retired in connection with sale of Asia-Pacific operations	$	838
Note receivable from sale of southeast plants		48
Remarketing of senior notes		1,625
Reclassification of guaranteed preferred beneficial interests in subordinated notes to long-term debt					600
Reclassification of long-term debt to notes payable and commercial paper					500

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 September 30, 2003, was increased by approximately $2 million, from a loss of $106 million to a loss of $104 million, for the three months and reduced by approximately $73 million, from income of $346 million to income of $273 million, for the nine months ended September 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 (GAAP) 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.

Change in Accounting Policies. During the quarter ended September 30, 2004, the date of the annual goodwill impairment test for Field Services was changed to August 31st from September 30th. August 31st was selected to perform the annual goodwill impairment test because this earlier date allows Field Services to complete the goodwill impairment test within the same quarter as the testing date. In addition, the change in date will be consistent with the annual goodwill impairment test date used by Duke Capital’s other business segments. The change in testing goodwill date did not delay, accelerate or avoid an impairment charge. Accordingly, management believes that the accounting change described above is to a date which is preferable under the circumstances.

In addition, as discussed in Note 1 to the Consolidated Financial Statements in Duke Capital’s Form 10-K/A for the year ended December 31, 2003, as of January 1, 2003, Duke Capital adopted the remaining provisions 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 Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.”

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 September 30, 2003, 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 in the Consolidated Statement of Cash Flows. The proceeds from the sales of those properties, as well as proceeds from the sales of “legacy” land, were presented as part of the reconciliation of net income to net cash flows from operating activities, and thus were included in cash flows from operating activities.

Duke Capital has since determined that both Crescent’s purchases and sales of commercial and multi-family properties, and the proceeds from the sales of “legacy” land, should be presented as a component of cash flows from investing activities. Additionally, the purchases and sales 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 sales were presented there. As a result of the change, net cash provided by operating activities decreased by $231 million, from $1,522 million to $1,291 million, and net cash provided by investing activities increased by $231 million, from $170 million to $401 million, in the September 30, 2003 Consolidated Statement of Cash Flows.

Also in Duke Capital’s Quarterly Report on Form 10-Q for September 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, Maintenance and Other expenses in the Consolidated Statements of Operations. Consistent with the changes in presentation noted above for the Consolidated Statements of Cash Flows, 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 $36 million for the three months and $47 million for the nine months ended September 30, 2003, rather than presented in revenues, and Operation, Maintenance and Other expenses. As a result of this change, total operating revenues decreased by $54 million, from $4,010 million to $3,956 million, for the three months and $94 million, from $12,315 million to $12,221 million, for the nine months ended September 30, 2003. Also as a result of this change, total operating expenses decreased by $18 million, from $3,996 million to $3,978 million, for the three months and $47 million, from $11,305 million to $11,258 million, for the nine months ended September 30, 2003.

Reclassified amounts also included increases to both Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues and to Natural Gas and Petroleum Products Purchased of $264 million for the three months and $723 million for the nine months ended September 30, 2003, related to Field Services segment.

Other 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 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 September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net Income, as reported	$	(1,010	)	$	(104	)	$	(637	)	$	273
Add: stock-based compensation expense included in reported net income, net of related tax effects		4			—			8			5
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(6	)		(6	)		(16	)		(20	)

Pro forma net income	$	(1,012	)	$	(110	)	$	(645	)	$	258

3. Inventory

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

Inventory (in millions)


	September 30, 2004		December 31, 2003
Natural gas and natural gas liquid products held in storage for transmission, processing, and sales commitments	$	329	$	299
Materials and supplies		136		139
Petroleum products		34		45

Total inventory	$	499	$	483

4. Debt and Credit Facilities and Preferred and Preference Stock of Duke Capital’s Subsidiaries

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 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. In September 2004, Duke Capital repaid approximately $50 million of Australian debt from assets that were held in a consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific operations. 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 August 2004, Duke Capital redeemed the entire issue of its 8.375% debt due to an affiliate in 2029 for $250 million, in connection with the redemption of its Duke Capital Financing Trust III 8.375% Trust Preferred Securities. As the securities were redeemed at par, security holders received $25 per preferred security held, plus accrued and unpaid distributions to the redemption date.

In the third quarter of 2004, Duke Capital purchased an additional $101 million of its outstanding notes in the open market. These purchases included $10 million of Duke Capital 6.75% senior notes due February 15, 2032 and $91 million of Duke Capital 5.50% senior notes due March 1, 2014. These securities were purchased at the then-current market price plus accrued interest 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. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the third quarter of 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that are being held by the collateral agent and, upon maturity, will be used to satisfy the forward stock purchase contract component of the 8.00% Equity Units scheduled for November 16, 2004.

On October 27, 2004, Duke Capital prepaid a portion of a Duke Energy North America (DENA) floating rate facility. The payment consisted of $565 million of this floating rate facility, an associated $35 million working capital facility and accrued interest on the facilities.

Credit Facilities Capacity and Restrictive Debt Covenants. During the nine months ended September 30, 2004, credit facilities capacity was reduced by approximately $730 million compared to December 31, 2003, primarily relating to the divested Australian operations as discussed in Note 8. 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 issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

On October 18, 2004 a new $120 million bilateral credit facility was established by Duke Capital with an expiration date of July 15, 2009. Also on October 18, a new $130 million bilateral credit facility was established by Duke Capital with an expiration date of October 18, 2007. Duke Capital intends to use both of these facilities for issuing letters of credit to support the business activities of its subsidiaries.

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 September 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.

The credit facilities as of September 30, 2004 are included in the following table.

Credit Facilities Summary as of September 30, 2004 (in millions)


	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		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	$	—	$	739	$	739

Westcoast Energy Inc.
$79 two-year syndicated ^{b, d}	July 2005
$157 three-year syndicated ^{b, e}	June 2007
Total Westcoast Energy Inc.			236		—		—		—

Union Gas Limited
$236 364-day syndicated ^{f, g}	June 2005		236		—		—		—

Duke Energy Field Services, LLC
$250 364-day syndicated ^{c, h, i}	March 2005		250		—		—		—

Total ^j		$	1,922	$	—	$	739	$	739

^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 September 30, 2004.

^e	Credit facility is denominated in Canadian dollars and was 200 million Canadian dollars as of September 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 September 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.

Preferred and Preference Stock of Duke Capital’s Subsidiaries. On June 1, 2004, Westcoast 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.

On October 15, 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 9. The Series 9 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 125 million Canadian dollars.

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 September 30, 2004 and $6 million for the same period in 2003. The income allocated by Duke Energy was $20 million for the nine month period ended September 30, 2004 compared to $19 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 September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Westcoast
Service cost	$	2		$	2		$	6		$	5
Interest cost on projected benefit obligation		6			6			19			17
Expected return on plan assets		(6	)		(6	)		(17	)		(18	)
Amortization of loss		1			—			2			—

Net periodic pension costs	$	3		$	2		$	10		$	4

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 made voluntary contributions of $250 million to its defined benefit retirement plan in October 2004 and $181 million in September 2003.

Duke Energy’s policy is to fund its Canadian 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 Energy has contributed $14 million to the Westcoast plans during the nine-months ended September 30, 2004, and anticipates making total contributions of approximately $30 million in 2004. Duke Energy made contributions of $11 million to the Westcoast plans in 2003.

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 September 30, 2004 and $5 million for the same period in 2003. The expense allocated by Duke Energy was $15 million for the nine month period ended September 30, 2004 and $15 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 September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Westcoast
Service cost benefit	$	1	$	1	$	2	$	2
Interest cost on accumulated post-retirement benefit obligation		1		1		3		2
Amortization of loss		—		—		1		—

Net periodic post-retirement benefit costs	$	2	$	2	$	6	$	4

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

Comprehensive (Loss) Income. Comprehensive (loss) income includes net (loss) income and all other non-owner changes in equity.

Total Comprehensive (Loss) Income (in millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net (Loss) Income	$	(1,010	)	$	(104	)	$	(637	)	$	273

Other comprehensive income
Foreign currency translation adjustments		247			294			(31	)		698
Net unrealized gains (losses) on cash flow hedges ^a		90			(130	)		257			290
Reclassification into earnings from cash flow hedges ^b		16			(37	)		(41	)		(155	)

Other comprehensive income, net of tax		353			127			185			833

Total Comprehensive (Loss) Income	$	(657	)	$	23		$	(452	)	$	1,106

Net unrealized gains (losses) on cash flow hedges, net of $84 million tax expense for the three months ended September 30, 2004, $95 million tax benefit for the three months ended September 30, 2003, $151 million tax expense for the nine months ended September 30, 2004, and $174 million tax expense for the nine months ended September 30, 2003.

Reclassification into earnings from cash flow hedges, net of $6 million tax benefit for the three months ended September 30, 2004, $9 million tax benefit for the three months ended September 30, 2003, $23 million tax benefit for the nine months ended September 30, 2004, and $93 million tax benefit for the nine months ended September 30, 2003.

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
Balance as of December 31, 2003	$	309		$	316	$	(25	)	$	600
Other comprehensive income changes year-to-date (net of $128 tax expense)		(31	)		216		—			185

Balance as of September 30, 2004	$	278		$	532	$	(25	)	$	785

7. Acquisitions, Dispositions, and Impairments

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 known 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, Field Services 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.

In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which DEFS owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Capital recognizing a pretax impairment of approximately $13 million, which was approximately $4 million net of minority interest. An additional 15% interest in Dauphin Island Gathering Partners (DIGP) was also purchased, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

The pro forma results of operations for this acquisition do not materially differ from reported results.

Dispositions. For the nine months ended September 30, 2004, the sale of other assets (which excludes assets held for sale as of September 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 $606 million in proceeds, and net pre-tax losses of $367 million recorded in Losses on Sales of Other Assets, net and pre-tax gains of $9 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments 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 $19 million in net proceeds. Those sales resulted in total pre-tax gains of approximately $16 million, of which $11 million was recorded in Losses on Sales of Other Assets, net and $5 million was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included the sale of storage gas related to the Canadian distribution operations in the second quarter of 2004 and the sale of Natural Gas Transmission’s interest in the Millennium Pipeline Project in the third quarter of 2004.

•

DENA’s asset sales totaled approximately $540 million in net proceeds, which includes a note receivable of $48 million. Those sales resulted in pre-tax losses of $374 million which were recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included:

•

Some turbines and surplus equipment in the first and second quarter of 2004. This sale was anticipated in 2003, so related losses were recorded in 2003.

•

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, as part of the sale, DETM paid a third party an amount approximating the carrying value of the contracts.

•

A 25% undivided interest in DENA’s Vermillion facility in the second quarter of 2004. This sale was anticipated in 2003, so related losses were recorded in 2003. Duke Capital still owns the remaining 75% interest in the Vermillion facility.

•

DENA’s merchant power generation business in the southeastern United States. Duke Capital decided to sell those assets in 2003, and recorded an impairment charge in 2003 since the assets’ carrying values exceeded their estimated fair values. The sale of those assets to KGen Partners LLC (KGen) obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a pre-tax loss of approximately $360 million recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Nearly all of the loss was recognized in the first quarter of 2004 to reduce the assets’ carrying value to their estimated fair values, and approximately $4 million of the loss was recognized in the third quarter of 2004 upon closing. The fair value of the plants used for recording the loss in the first quarter was based on the sales price of approximately $475 million, as announced on May 4, 2004. The actual sales price consisted of $420 million of cash and a $48 million note receivable from KGen, which bears variable interest at LIBOR (London Interbank Offered Rate) plus 13.625% per annum, compounded quarterly. The note is secured by a fourth lien on (i) substantially all of KGen’s

assets and (ii) stock of KGen LLC (KGen’s owner), each subject to certain permitted liens and a first lien on cash in certain KGen accounts. The note matures with a balloon payment of principal and interest due no later than 7.5 years after the closing date.

Duke Capital retains certain guarantees related to the sold assets. In conjunction with the sale, 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 one of the plants 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. DENA will continue to provide services under a long-term operating agreement for one of the plants. As a result of DENA’s significant continuing involvement in the operations of the plants, this transaction did not qualify for discontinued operations presentation, as prescribed by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” However, this continuing involvement does not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.”

•

International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico on September 8, 2004. The sale resulted in $60 million in net proceeds and an approximate $2 million pre-tax gain recorded to (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. A $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations, related to a note receivable from Cantarell, was recorded in the first quarter of 2004.

•

Asset sales within Other totaled $34 million in net proceeds. Those sales resulted in net pre-tax losses of $7 million which were recorded in Losses 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.

For the nine months ended September 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $413 million of proceeds, and $149 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 and four smaller commercial projects in the third quarter; the Alexandria land tract in the Washington, D.C. area in June 2004; and several large land sales closed in the first quarter of 2004.

Impairments. In the third quarter of 2004, Duke Capital recorded impairments of approximately $22 million related to Field Services’ operating assets. The majority of this charge relates to the MBPP exchange transaction discussed above.

Duke Capital recorded an impairment totaling approximately $23 million of equity method investments at Field Services, included in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations in the third quarter of 2004. The impairment charge was related to management’s assessment of the recoverability of some equity method investments. Duke Capital determined that these assets, which are located Onshore Gulf of Mexico, were impaired, therefore they were written down to fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models.

Duke Capital recorded a $254 million goodwill impairment charge in the third quarter 2003 to write off all DENA goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflects the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Capital used a discounted cash flow analysis to perform the

assessment. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Capital incorporated current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices.

8. Assets Held for Sale and Discontinued Operations

Assets Held for Sale. 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 of 2004, 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. In September 2004, Duke Capital repaid approximately $50 million of remaining Australian debt from assets that were held in a fully-funded consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific operations. 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 Discontinued Operations, net of tax, in the Consolidated Statements of Operations. See Note 4 for a discussion of the impact of this transaction to consolidated long-term debt.

On September 21, 2004, Duke Capital signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving will purchase Duke Capital’s interests in Bayside Power L.P. (Bayside). Irving has the right to terminate the agreement at any time prior to February 21, 2005, however, if Irving fails to terminate the agreement prior to February 21, 2005, the terms of the purchase and sale become binding. If Irving does not terminate the agreement, closing will occur upon receipt of required third party consents and regulatory approvals. Closing is expected to occur in 2005. As a result of the above agreement, Duke Capital has presented the assets and liabilities of Bayside as “held for sale” in the September 30, 2004 Consolidated Balance Sheet.

On October 13, 2004, Duke Capital completed the sale of the Moapa facility to Nevada Power Company, resulting in a pre-tax gain of approximately $130 million which will be reported in Losses on Sales of Other Assets, net in the Consolidated Statement of Operations in the fourth quarter of 2004. The Moapa asset was impaired in 2003 and is classified as Assets Held for Sale in the September 30, 2004 Consolidated Balance Sheet. This asset is not reported in Discontinued Operations in the Consolidated Statement of Operations, as among other considerations, the facility never entered into operations and has no associated historical operating revenues or significant costs.

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. If a project has distinguishable operations and cash flows, and Crescent does not retain any significant continuing involvement in the project after it is sold, and cash flows of the sold projects have been eliminated from Crescent’s ongoing operations, SFAS No. 144 requires the real estate projects to be classified as discontinued operations. During 2004, Crescent sold one residential and one commercial property included in Assets Held for Sale on the Consolidated Balance Sheet resulting in sales proceeds of approximately $14 million. The $4 million gain on these sales was included in Discontinued Operations – Net (Loss) Gain on Dispositions, net of tax, in the Consolidated Statements of Operations. As of September 30, 2004, Crescent had three commercial properties and one multi-family property classified as Assets Held for Sale in the Consolidated Balance Sheet. Crescent expects to have

significant continuing involvement after the sale in two of those commercial properties and therefore the results of those operations are not included in Discontinued Operations in the Consolidated Statement of Operations.

In the third quarter of 2004, Field Services recorded an impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some gathering, processing, compression and transportation assets being held for sale. The estimated fair value of these assets less cost to sell was $26 million and they were classified as Assets Held for Sale in the September 30, 2004 Consolidated Balance Sheet.

The following are significant items classified as “held for sale” in the Consolidated Balance Sheets as of December 31, 2003:

•

International Energy’s European operations ^a

•

International Energy’s Asia-Pacific power generation and natural gas transmission businesses ^a

•

Some turbines and related equipment owned by DENA

•

Duke Capital Partners, LLC’s (DCP’s) merchant finance business ^a

In 2004, several of the above items were sold, including International Energy’s Asia-Pacific assets, substantially all of the assets of DCP’s merchant finance business, and some of DENA’s turbines and related equipment, as discussed in Note 7. The following significant items have been added to and are classified as “held for sale” in the Consolidated Balance Sheets as of September 30, 2004:

•

DENA’s Moapa facility

•

DENA’s Bayside facility ^b

•

Some gathering, processing, compression and transportation assets owned by Field Services ^a

•

Commercial office buildings owned by Crescent in which it expects significant continuing involvement through a third party leasing and management agreement with the new owners of the buildings

•

Commercial and multi-family properties owned by Crescent in which it expects no significant continuing involvement after the sale ^a

^a	Operating results for these businesses are classified as Discontinued Operations in the Consolidated Statements of Operations (see results below)

Bayside was consolidated as a result of the adoption of FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities,” on March 31, 2004. As a result, Bayside’s operating results for the period April 1 to September 30, 2004 are included in Discontinued Operations in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations.

The following table presents the carrying values as of September 30, 2004 and December 31, 2003 of the major classes of Assets and associated Liabilities Held for Sale in the Consolidated Balance Sheets.

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


	September 30, 2004		December 31, 2003
Current assets	$	125	$	424
Investments and other assets		150		379
Property, plant and equipment, net		86		1,065

Total assets held for sale	$	361	$	1,868

Current liabilities	$	41	$	651
Long-term debt		13		514
Deferred credits and other liabilities		1		223

Total liabilities associated with assets held for sale	$	55	$	1,388

Discontinued Operations. The following are the operations classified as Discontinued Operations in the Consolidated Statement of Operations for the three and nine-month periods ended September 30, 2004:

•

International Energy’s European operations

•

International Energy’s Asia Pacific power generation and natural gas transmission businesses

•

DCP’s merchant finance business

•

DENA’s Bayside facility ^a

•

Some gathering, processing, compression and transportation assets owned by Field Services

•

Commercial, residential, and multi-family properties owned by Crescent in which it expects no significant continuing involvement after the sale ^b

In addition to those items above, excluding Bayside and some Crescent properties, the nine-month period ended September 30, 2003 contains some commercial and multi-family properties owned by Crescent that were sold in the fourth quarter of 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.

As a result of Bayside being classified as an equity investment prior to April 2004, but consolidated under the provisions of FIN 46 at March 31, 2004, the results of operations in 2003 and the first three months of 2004 are not presented in Discontinued Operations in the Consolidated Statement of Operations

^b	These properties had no operating results in 2003

The following table summarizes the operating results classified as Discontinued Operations in the Consolidated Statements of Operations.

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 September 30, 2004
International Energy	$	—	$	(10	)	$	(1	)	$	(9	)	$	—		$	(5	)	$	5
Field Services		10		—			—			—			(16	)		(6	)		(10	)
DENA		20		(3	)		(1	)		(2	)		—			—			—
Crescent		1		—			—			—			7			3			4

Total consolidated	$	31	$	(13	)	$	(2	)	$	(11	)	$	(9	)	$	(8	)	$	(1	)


Three Months Ended September 30, 2003
International Energy	$	143	$	(13	)	$	3		$	(16	)	$	(2	)	$	(52	)	$	50
Field Services		29		1			—			1			—			—			—
Crescent		2		—			—			—			—			—			—
Other		5		3			1			2			(23	)		(9	)		(14	)

Total consolidated	$	179	$	(9	)	$	4		$	(13	)	$	(25	)	$	(61	)	$	36


Nine Months Ended September 30, 2004
International Energy	$	82	$	(7	)	$	—		$	(7	)	$	295		$	22		$	273
Field Services		54		1			—			1			(14	)		(5	)		(9	)
DENA		78		(5	)		(2	)		(3	)		—			—			—
Crescent		2		—			—			—			7			3			4
Other		1		2			1			1			—			—			—

Total consolidated	$	217	$	(9	)	$	(1	)	$	(8	)	$	288		$	20		$	268


Nine Months Ended September 30, 2003
International Energy	$	551	$	2		$	2		$	—		$	(3	)	$	(52	)	$	49
Field Services		296		7			2			5			19			7			12
Crescent		4		—			—			—			—			—			—
Other		19		1			2			(1	)		(23	)		(9	)		(14	)

Total consolidated	$	870	$	10		$	6		$	4		$	(7	)	$	(54	)	$	47

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.”

entities previously part of Other Operations and now within Other still remain, primarily: DukeNet Communications LLC, Bison Insurance Company Limited (Bison) 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.

Except as discussed in Note 1, the 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 (Loss) from Continuing Operations before Income Taxes
Three Months Ended September 30, 2004
Natural Gas Transmission	$	585	$	53		$	638		$	265
Field Services		2,487		19			2,506			67
Duke Energy North America		521		21			542			(17	)
International Energy		146		—			146			64
Crescent		77		—			77			43

Total reportable segments		3,816		93			3,909			422
Other		28		11			39			46
Eliminations		—		(104	)		(104	)		—
Interest expense		—		—			—			(273	)
Minority interest expense and other ^a		—		—			—			22

Total consolidated	$	3,844	$	—		$	3,844		$	217

Three Months Ended September 30, 2003
Natural Gas Transmission	$	590	$	51		$	641		$	280
Field Services		1,996		80			2,076			51
Duke Energy North America		1,108		33			1,141			(411	)
International Energy		151		—			151			44
Crescent		44		—			44			39

Total reportable segments		3,889		164			4,053			3
Other		67		17			84			10
Eliminations		—		(181	)		(181	)		—
Interest expense		—		—			—			(277	)
Minority interest expense and other^a		—		—			—			26

Total consolidated	$	3,956	$	—		$	3,956		$	(238	)

^a	Other 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
Nine Months Ended September 30, 2004
Natural Gas Transmission	$	2,202	$	162		$	2,364		$	974
Field Services		7,092		115			7,207			253
Duke Energy North America		1,749		63			1,812			(612	)
International Energy		447		—			447			161
Crescent		216		—			216			190

Total reportable segments		11,706		340			12,046			966
Other		73		45			118			103
Eliminations		—		(385	)		(385	)		—
Interest expense		—		—			—			(808	)
Minority interest expense and other ^a		—		—			—			75

Total consolidated	$	11,779	$	—		$	11,779		$	336

Nine Months Ended September 30, 2003
Natural Gas Transmission	$	2,105	$	196		$	2,301		$	1,009
Field Services		5,969		674			6,643			136
Duke Energy North America		3,331		168			3,499			(177	)
International Energy		492		—			492			175
Crescent		141		—			141			61

Total reportable segments		12,038		1,038			13,076			1,204
Other		183		57			240			62
Eliminations		—		(1,095	)		(1,095	)		—
Interest expense		—		—			—			(797	)
Minority interest expense and other ^a		—		—			—			23

Total consolidated	$	12,221	$	—		$	12,221		$	492

^a	Other 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)


	September 30, 2004			December 31, 2003
Natural Gas Transmission	$	16,589		$	16,384
Field Services		6,539			6,417
Duke Energy North America		7,868			9,702
International Energy		3,331			4,550
Crescent		1,576			1,653

Total reportable segments		35,903			38,706
Other		2,617			1,945
Eliminations ^a		(510	)		(544	)

Total consolidated assets	$	38,010		$	40,107

^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 $4,002 million as of September 30, 2004 and $3,962 million as of December 31, 2003, with $3,259 million as of September 30, 2004 allocated to Natural Gas Transmission, $494 million to Field Services, $242 million to International Energy and $7 million to Crescent. The $40 million increase from December 31, 2003 to September 30, 2004 was related solely to foreign currency exchange rate fluctuations of $35 million at Natural Gas Transmission, $4 million at International Energy and $1 million at Field Services.

10. Risk Management Instruments

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

Derivative Portfolio Carrying Value (in millions)


	September 30, 2004			December 31, 2003
Hedging	$	817		$	439
Trading		75			185
Undesignated		(300	)		(220	)

Total	$	592		$	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 $209 million as of September 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 over the next 6 years.

The $378 million increase in the hedging derivative portfolio carrying value is due primarily to changes in forward gas prices, partially offset by the realization of gas hedge gains as well as other hedge activity.

The $80 million decrease in the undesignated derivative portfolio fair value is due primarily to changes in power and gas prices on forward contracts formerly designated as hedges of DENA’s southeastern plants and deferred western plants along with settlements of net mark-to-market gains during the nine months ended September 30, 2004.

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		(112	)
Other changes in fair values		2

Fair value of contracts outstanding as of September 30, 2004	$	75

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 pipeline that transports gas within a state for ultimate consumption in that state under the jurisdiction of a state natural gas regulatory authority, and that may also transport gas in interstate commerce under rates and terms of service regulated by the FERC pursuant to rules applicable to interstate pipelines under the Natural Gas Act.)

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 Energy’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 Energy has implemented compliance programs to meet the requirements of the order. Duke Capital expects the orders to have no material adverse effect on its consolidated results of operations, cash flows or financial position.

FERC Audits of Pre-Order 2004 Standards of Conduct. Since September 2003, the FERC has been conducting a public audit of compliance with the pre-Order 2004 standards of conduct by Texas Eastern Transmission, LP. Duke Capital anticipates that a final report will be issued by the FERC in the near future, which will contain several recommendations to enhance compliance, some of which have already been implemented. Duke Capital expects the FERC’s recommendations or findings 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 August 23, 2004, the NEB approved the BC Pipeline’s application for 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 those 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 dekatherm (Dth) to $1.07/Dth. A FERC order accepted the rate filing and suspended the rates until January 1, 2005, when they will become effective, subject to refund. The rate case has been set for hearing.

International Energy. Brazil Regulatory Environment. In 2004, a new energy law was enacted in Brazil that is changing the electricity sector’s regulatory framework. The regulations implementing the new law are still in the process of being formulated. The new energy law created a regulated and non-regulated market that will coexist. The regulated market consists of auctions that will be conducted by the government for the sale of power to the distribution companies. The distribution companies will have to fully contract their estimated electricity demand, principally through these regulated auctions. In the non-regulated market, generators, traders and non-regulated customers will be permitted to enter into bilateral electricity purchase and sale contracts. It is anticipated that the first regulated auction will be held in December 2004. In this auction, distribution companies will contract their estimated demand for the period from 2005 to 2015. The contract structure within the auction process is anticipated to be eight-year contracts with delivery periods commencing in 2005, 2006 and 2007. Regulations defining the auction methodology are still being enacted. At this time it is too early to determine the impact, if any, that these changes will have on Duke Capital’s consolidated results of operations, cash flows or financial position.

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.

Clean Water Act. The Environmental Protection Agency’s (EPA’s) final Clean Water Act - Section 316(b) rule was promulgated and became effective July 9, 2004. The rule establishes best technology available (BTA) requirements for cooling water intake structures for existing steam electric generating facilities to protect fish and other aquatic organisms. Duke Capital’s three natural gas-fired generating facilities in California are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to generate information for use in determining facility-specific BTA requirements and cost estimates for implementation. These studies will be completed over the next three to five years. Once the compliance measures for a facility are approved by regulators, implementation will begin. Due to the wide range of BTA measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the information obtained in the CDS, Duke Capital is not able to estimate its cost for complying with the rule at this time. Once the compliance measures for a facility are determined, it will typically have five years or more to implement the measures.

Air Quality Control. In 1998, the 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. Russia recently approved ratification of the Kyoto Protocol which will trigger its entry into force and obligate Canada 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. The June 2004 Canadian elections, which resulted in a minority government led by the Liberal party, might also affect the final policy timing and outcome. The Canadian Prime Minister, on October 5, 2004, reaffirmed the government’s commitment to implementing a national plan to meet its Kyoto obligation.

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 are discussing the possibility of implementing 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 $74 million as of September 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. Since 2000, plaintiffs have filed 35 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, one suit has been dismissed voluntarily and eight suits have been dismissed on filed rate and federal preemption grounds. Plaintiffs have appealed the non-voluntary dismissals. In September 2004, the U.S. Ninth Circuit Court of Appeals affirmed the dismissal of one of the lawsuits.

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 California Independent System Operator and the California Power Exchange 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 U.S. Ninth Circuit 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 Energy 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 Energy received unjust or unreasonable rates for the sale of electricity during the settlement period. The settlement resolves:

•

All western refund proceedings pending before the FERC

•

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

•

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

•

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

On October 1, 2004, Duke Energy and the California parties jointly submitted to FERC the documents evidencing their previously announced settlement agreement.

In Lockyer v. FERC, the U.S. Ninth Circuit Court of Appeals ruled in September 2004 that while FERC’s authorization of market based rate tariffs complied with the Federal Power Act, the failure by sellers of electricity to file appropriate quarterly reports provides the FERC with authority to award refunds relating to the period prior to October 2000. The court declined to order refunds requested by the State of California but remanded the case to the FERC for further proceedings consistent with its opinion. The Duke Energy California Settlement Agreement, upon approval, will resolve refund issues relating to the post-October 2000 refund period as well as the pre-October 2000 period that was at issue in the Lockyer case. While the Lockyer ruling should not affect Duke Energy’s settlement, the decision could give rise to potential refund liability at the FERC for market-based rate sellers generally to the extent quarterly reports filed by those entities are incomplete or inaccurate.

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 U.S. Second Circuit Court of Appeals. The court heard oral arguments in the appeal on November 3, 2004. Duke Energy is vigorously defending the 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 but did not initiate any litigation within the stated timeframe. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds 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 the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. 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. The case claims that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the Court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.

Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the Securities and Exchange Commission (SEC) and to grand jury subpoenas issued by the U.S. Attorney’s office in Houston, Texas. The information requests and subpoenas sought documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in 2002 that the SEC formalized its trading-related investigation and is cooperating with the SEC. 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/Sonatrading Arbitration. 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 hearing on damages issues has been set for September 2005.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in Texas against Duke LNG and PanEnergy Corp. (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 under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages. Cross motions for partial summary judgment regarding the letter of credit issue have been filed and are pending. No trial date has been set. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with the Sonatrach and Citrus matters.

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. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain ExxonMobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Venture and wrongfully failed to assume certain related gas supply agreement with other parties. These matters are in very early stages, and it is not possible to predict with certainty the damages that might be incurred by Duke Capital or any of its affiliates as a result of these matters.

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, arbitration and mediation panels, 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 domestic 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 September 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 September 30, 2004, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Capital estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of September 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 September 30, 2004, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.

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

•

DCS will exercise its options under the Duke Power Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract,

•

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 September 30, 2004 was approximately $2.4 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 $675 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $200 million of the performance guarantees expire between 2004 and 2005, with the remaining performance guarantees expiring after 2006 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method 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 September 30, 2004 was approximately $60 million. Of those guarantees, approximately $10 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. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of September 30, 2004 was approximately $355 million. Of this amount, approximately $300 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities and approximately $5 million relates to affiliated entities such as DEM. Approximately $120 million of the letters of credit expire in 2004, with the remainder expiring in 2005.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of September 30, 2004, Duke Capital had guaranteed approximately $105 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2004 and 2005. Of this amount, approximately $20 million relates to affiliated entities such as DEM and approximately $15 million relates to obligations of less than wholly owned consolidated entities.

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 less than wholly-owned entity. As of September 30, 2004, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, with approximately $8 million expiring in 2009 and the remainder having no contractual expiration. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly-owned entities, with approximately $5 million expiring 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 DukeSolutions 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.

Additionally, in August 2004, Duke Capital issued a $120 million letter of credit to Georgia Power Company, which expires in 2005, related to the obligation of a KGen subsidiary under a seven year power sales agreement, commencing in May 2005, as discussed in Note 7. Duke Capital will be required to reissue this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Capital will operate the Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has issued an indemnification to reimburse Duke Capital for any payments made under the $120 million letter of credit.

Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s maximum potential exposure under these indemnification agreements can range from a specified 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 September 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 September 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 Non-controlling 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 September 30, 2004 the carrying value of the entity’s non-controlling interest of approximately $48 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 $211 million as of September 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, due to certain contract clarifications pursuant to a contract amendment entered into in April 2004 (as further discussed in Note 13), Duke Capital no longer holds a significant variable interest in DCS.

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 Capital 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 of anticipated prescription drug subsidy, the accumulated post-retirement benefit obligation for Duke Energy’s U.S. Plan decreased by $96 million. The after-tax effect on Duke Capital’s post-retirement benefit cost was not material for the three months and for the nine months ended September 30, 2004.

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

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

The following new accounting standard has been issued, but has not yet been fully adopted by Duke Capital as of September 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 September 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. Income Tax Expense

The effective income tax rate for the three and nine months ended September 30, 2004, compared to the same periods in 2003, increased as a result of $1,030 million of tax expense from the change in deferred taxes as a result of the Duke Energy Americas, LLC (DEA) reorganization, the pass-through of income tax benefit to Duke Energy, partially offset by the reduction of $45 million of state and federal income tax reserves (see discussion below).

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, 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 recognized federal and state tax expense of approximately $1,030 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, reflected, through consolidation, the elimination of the $1,030 million deferred tax asset at Duke Capital and the creation of a deferred tax asset of approximately $1,030 million on its balance sheet. Duke Energy additionally recognized an approximate $48 million income tax benefit and corresponding deferred tax asset as a result of revaluing its deferred taxes to reflect a change in effective state tax rates.

As a result of Duke Energy realigning certain subsidiaries as discussed above, approximately $90 million for the three months and approximately $110 million for the nine months ending September 30, 2004 of tax benefits relating to the pretax losses from DEA and Duke Capital, for the periods after the entities became LLC’s in 2004, were recorded at Duke Energy.

The $45 million reserve reduction occurred in the second quarter of 2004 due to the resolution of various income tax positions taken by Duke Capital and changes in estimates.

16. Subsequent Events

On October 25, 2004, Crescent closed on the remaining land holdings of the Arlington County portion of the Potomac Yard project in the Washington D.C. area. Total proceeds from the transaction were approximately $80 million and the pre-tax gain on sale of approximately $25 million will be recorded in the fourth quarter.

As disclosed in Note 5, in October 2004 Duke Energy, the parent of Duke Capital, made voluntary contributions of $250 million to its U.S. defined benefit retirement plan.

In October 2004, the American Jobs Creation Act of 2004 (the Act) was signed into law. The Act creates a temporary incentive for U.S. entities with foreign earnings to repatriate accumulated foreign earnings, subject to certain limitations, by providing an 85% dividends received deduction for certain repatriated earnings. Duke Energy currently anticipates repatriating approximately $500 million of accumulated foreign earnings in 2005. Duke Capital does not anticipate any material tax expense as a result of the Act; however, Duke Energy anticipates recording approximately $45 million of tax expense in the fourth quarter of 2004. Additionally, the Act establishes a deduction for certain qualified domestic production activities, such as gas extraction and electric production. The FASB is currently considering whether to provide guidance on accounting for the qualified domestic production activities deduction. Therefore, it is currently uncertain how this deduction under the Act will impact the Duke Capital consolidated financial statements.

On November 12, 2004, DETM entered into an agreement to sell some of its remaining western natural gas transportation capacity commitments and related supply transactions with an expected effective date of January 2005. The sales transaction is subject to the customary bidding process for interstate natural gas transportation capacity contracts, which is expected to be completed in late November. As part of the sales transaction, DETM expects to pay approximately $28 million in sales proceeds. This transaction is expected to result in a loss of approximately $54 million, before the effects of minority interest, which will be recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations in the fourth quarter of 2004.

On November 12, 2004, Duke Capital sold one of DENA’s deferred facilities, Luna, to Tucson Electric Power Company, Phelps Dodge Energy Services and PNM Resources, Inc., for approximately $40 million in cash. This sale will result in an approximate gain of $39 million which will be recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations in the fourth quarter of 2004. The Luna plant was impaired in 2003 and is not reported in Discontinued Operations as, among other considerations, it never entered into operations and has no associated historical operating revenues or costs.

On November 15, 2004, Duke Capital entered into an agreement to sell certain gathering, compression and transportation assets located in Wyoming and Utah for approximately $28 million. The book value of these assets was written down in the third quarter of 2004 by $23 million ($16 million of net minority interest) to the sales price less costs to sell. The results of operations and cash flows related to these assets held for sale have been reclassified to discontinued operations for all periods presented. The transaction is scheduled to close in early 2005.

For information on subsequent events related to debt and credit facilities and preferred and preference stock, see Note 4 and for information on subsequent events related to litigation and contingencies, see Note 12. For information on the subsequent sale of the Moapa facility, see Note 8.

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 September 30,									Nine Months Ended September 30,
	2004			2003 ^a			Increase (Decrease)			2004			2003 ^a			Increase (Decrease)
Operating revenues	$	3,844		$	3,956		$	(112	)	$	11,779		$	12,221		$	(442	)
Operating expenses		3,379			3,978			(599	)		10,473			11,258			(785	)
Gains on sales of investments in commercial and multi-family real estate		28			36			(8	)		149			47			102
Losses on sales of other assets, net		(2	)		(80	)		78			(367	)		(78	)		(289	)

Operating income (loss)		491			(66	)		557			1,088			932			156
Other income and expenses, net		60			94			(34	)		198			425			(227	)
Interest expense		273			277			(4	)		808			797			11
Minority interest expense (benefit)		61			(11	)		72			142			68			74

Earnings (loss) from continuing operations before income taxes		217			(238	)		455			336			492			(156	)
Income tax expense (benefit)		1,215			(111	)		1,326			1,233			137			1,096

(Loss) income from continuing operations		(998	)		(127	)		(871	)		(897	)		355			(1,252	)
(Loss) income from discontinued operations, net of tax		(12	)		23			(35	)		260			51			209

(Loss) income before cumulative effect of change in accounting principle		(1,010	)		(104	)		(906	)		(637	)		406			(1,043	)
Cumulative effect of change in accounting principle, net of tax and minority interest		—			—			—			—			(133	)		133

Net (loss) income	$	(1,010	)	$	(104	)	$	(906	)	$	(637	)	$	273		$	(910	)

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

Overview of Drivers and Variances

Three Months Ended September 30, 2004 as Compared to September 30, 2003. Significant items that contributed to the decrease in net income for the quarter included:

•

A $1,030 million tax expense in 2004 related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes (see Note 15 to the Consolidated Financial Statements)

•

A $52 million income tax benefit in 2003 related to the write-off of goodwill at International Energy’s European operations in 2002, and

•

Impairments of $42 million (net of minority interest of $26 million) in 2004 related to asset impairments, losses on asset sales and write-down of equity investments at Field Services.

Those decreases in net income were partially offset by:

•

Severance charges in 2003 of $59 million across all segments except Field Services

•

A $254 million impairment in 2003 of all goodwill at Duke Energy North America (DENA), related primarily to the trading and marketing business

•

A settlement with the Commodity Futures Trading Commission (CFTC) in 2003 of $17 million (net of minority interest of $11 million) recorded at DENA, and

•

Lower plant depreciation and operating costs at DENA as a result of the sale of the southeast region plants in 2004.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003. In addition to the quarterly items described above, significant items that contributed to the decrease in net income for the nine months included:

•

An approximate $360 million pre-tax charge in the first quarter of 2004 associated with the sale of DENA’s southeastern plants (see Note 7 to the Consolidated Financial Statements)

•

A $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel

•

A $105 million pre-tax charge in 2004 related to the California and western U.S. energy markets settlement (see Note 12 to the Consolidated Financial Statements), and

•

Decreased earnings at DENA in 2004 due primarily to lower net natural gas sales volumes, due primarily to the continued wind down of Duke Energy Trading and Marketing, LLC (DETM, Duke Capital’s 60/40 joint venture with ExxonMobil Corporation), and higher plant fuel costs due to overall higher realized natural gas prices in 2004.

Those items were partially offset by:

•

A $295 million pre-tax gain ($273 million net of tax) recorded in 2004 on the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business and its European operations

•

A $109 million (net of minority interest of $5 million) pre-tax gain in 2004 related to the settlement of the Enron bankruptcy proceedings (see Note 12 to the Consolidated Financial Statements)

•

The reduction of various income tax reserves in 2004 totaling approximately $45 million (see Note 15 to the Consolidated Financial Statements)

•

Increased 2004 earnings at Field Services due to favorable effects of commodity prices and improved results from trading and marketing activities

•

Increased residential developed lot sales, commercial project and land management (“legacy” land sales) at Crescent, due to several large sales that closed in 2004, and

•

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

On a consolidated and a segment reporting basis, results of operations through September 30, 2004 may not be indicative of the full year.

Consolidated Operating Revenues

Three Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven by a $107 million decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, due primarily to:

•

A decrease in natural gas sales volumes associated with the continued wind down of DETM, partially offset by

•

Increased revenues at Field Services, due primarily to increased natural gas and NGL prices.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven by a $539 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, partially offset by

•

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

Partially offsetting the decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues was a $97 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 September 30, 2004 as Compared to September 30, 2003. The decrease was driven by:

•

A $254 million decrease in Impairment of Goodwill, due to the impairment in 2003 of all goodwill at DENA, related primarily to the trading and marketing business

•

A $139 million decrease in Fuel Used in Electric Generation and Purchased Power, due primarily to reduced volumes at DENA driven by the sale of the southeast region plants and overall lower plant production

•

A $129 million decrease in Operation, Maintenance and Other, due primarily to severance costs of $59 million in 2003 and the sale of DENA’s southeast region plants in 2004, and

•

A $98 million decrease in Natural Gas and Petroleum Products Purchased, due primarily to the continued wind down of DETM’s operations, partially offset by increased costs at Field Services due to higher average costs of raw natural gas supply (which is primarily due to an increase in average NGL and natural gas prices).

Nine Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven by a $478 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 of raw natural gas supply which is due primarily to an increase in average NGL and natural gas prices at Field Services.

In addition to the decrease in Natural Gas and Petroleum Products Purchased was a $254 million decrease in Impairment of Goodwill, due to the impairment in 2003 of all goodwill at DENA, related primarily to the trading and marketing business.

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 September 30, 2004 as Compared to September 30, 2003. The decrease was driven primarily by a $20 million decrease in land management or “legacy” land sales due to large sales in the prior year quarter of the Anthony and SouthPoint tracts, offset by a $12 million increase in net commercial project sales, representing the sale of four commercial projects in the current year quarter compared to the sale of one commercial project in the prior year quarter.

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

•

A $33 million increase in commercial project sales, due to the sale of a commercial project in the Washington, D.C. area in March 2004 and the sales of four smaller commercial projects in the current year third quarter, compared to one commercial project sale in the prior year

•

A $47 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 $23 million increase in “legacy” land sales, due to several large sales that closed in the first quarter of 2004.

Consolidated Losses on Sales of Other Assets, net

Three Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven primarily by an $84 million loss in 2003 associated with the write-down of DENA’s 25% interest in the Vermillion plant and other equipment to their estimated fair value.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003. The increase was due primarily to an approximate $360 million loss in 2004 associated with the sale of DENA’s southeastern plants, partially offset by the $84 million loss in 2003 noted above.

Consolidated Operating Income (Loss)

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

•

Decreased operating losses at DENA, due primarily to lower plant depreciation and operating costs from the sale of the southeast region plants in 2004, and charges in 2003 related to goodwill impairment, a CFTC settlement and severance accruals

•

Increased operating income at Field Services, due to the favorable effects of commodity prices, partially offset by NGL and raw natural gas sales volume declines and impairment charges associated with a planned shut down of a specific plant and a disposal of some assets, and

•

Increased operating income at Other, due to charges in 2003 related to severance and lower governance cost in 2004.

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

•

Increased operating income at Field Services, due to the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments

•

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

•

Increased operating losses at DENA, due to the increased losses from asset dispositions and reduced gross margin from lower net sales, values realized from hedge positions, and mark-to-market losses. These losses were partially offset by decreased plant depreciation and operating costs from the 2004 sale of the southeast region plants and the prior year goodwill impairment.

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

Consolidated Other Income and Expenses

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

•

A $23 million impairment charge at Field Services in 2004 related to management’s assessment of the recoverability of certain equity method investments, and

•

A $30 million gain on the sale of Natural Gas Transmission’s interests in Foothills Pipe Lines Ltd. in August 2003

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

•

A $178 million gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel,

•

A $31 million gain on the sales of Natural Gas Transmission’s interest in Alliance Pipeline and the associated Aux Sable liquids plant in the second quarter of 2003

•

A $30 million gain on the sale of Natural Gas Transmission’s interests in Foothills Pipe Lines Ltd. in August 2003, and

•

A $23 million impairment charge at Field Services in 2004 related to management’s assessment of the recoverability of certain equity method investments.

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 that were previously a part of Other Operations and are now within Other include primarily: DukeNet Communications LLC, Duke Capital’s 50% equity investment in Duke/Fluor Daniel (D/FD) and Bison Insurance Company, Limited. 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 segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

EBIT by Business Segment (in millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Natural Gas Transmission	$	265		$	280		$	974		$	1,009
Field Services		67			51			253			136
Duke Energy North America		(17	)		(411	)		(612	)		(177	)
International Energy		64			44			161			175
Crescent		43			39			190			61

Total reportable segment EBIT		422			3			966			1,204
Other		46			10			103			62
Interest expense		(273	)		(277	)		(808	)		(797	)
Minority interest expense and other ^a		22			26			75			23

Consolidated earnings (loss) from continuing operations before income taxes	$	217		$	(238	)	$	336		$	492

^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 September 30,							Nine Months Ended September 30,
(in millions, except where noted)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	638	$	641	$	(3	)	$	2,364	$	2,301	$	63
Operating expenses		387		393		(6	)		1,422		1,381		41
Gains on sales of other assets, net		3		3		—			12		4		8

Operating income		254		251		3			954		924		30
Other income, net of expenses		17		38		(21	)		36		117		(81	)
Minority interest expense		6		9		(3	)		16		32		(16	)

EBIT	$	265	$	280	$	(15	)	$	974	$	1,009	$	(35	)

Proportional throughput, TBtu ^a		652		679		(27	)		2,467		2,502		(35	)

^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 September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $17 million decrease as a result of the sale of Pacific Northern Gas Limited (PNG) in December 2003

•

A $14 million decrease in gas distribution revenues, due primarily to lower gas usage in the power market

•

A $17 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 $9 million increase from completed and operational business expansion projects in the United States.

Operating Expenses. The decrease was driven primarily by:

•

An $18 million decrease due to severance costs in the prior year quarter, offset by ad valorem tax benefits of $17 million during the same period

•

A $16 million decrease as a result of PNG operations sold in 2003

•

A $12 million decrease in gas purchases for distribution, due primarily to lower gas usage in the power market

•

A $12 million increase caused by foreign exchange impacts

•

A $5 million increase for business expansion projects placed in service.

Other Income, net of expenses. The decrease was driven primarily by a gain of $30 million on the sale of Natural Gas Transmission’s interests in Foothills Pipe Lines Ltd. in August 2003, partially offset by favorable foreign exchange variances as compared to 2003.

EBIT. EBIT decreased primarily as a result of prior year gains from sales of equity investments in 2003, partially offset by contributions from improved operational results and foreign exchange EBIT impacts from the strengthening Canadian currency in 2004.

During the third quarter of 2004, Natural Gas Transmission’s Moss Bluff storage field in southeast Texas experienced a fire. As a result of insurance coverage, this event did not have a significant impact on Natural Gas Transmission’s results of operations or cash flows for the third quarter of 2004, and is not expected to have a future significant impact. On November 2, 2004, two of the three storage caverns at Moss Bluff were returned to service. The remaining cavern is undergoing repairs and will likely return to service during the first half of 2005.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $121 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 $30 million increase due to improved operational results

•

A $30 million increase from completed and operational business expansion projects in the United States

•

A $70 million decrease as a result of the sale of Empire State Pipeline in February 2003 and of PNG in December 2003

•

A $54 million decrease in gas distribution revenues, resulting from lower gas usage in the power market partly offset by higher commodity costs that are passed through to customers without mark-up.

Operating Expenses. The increase was driven primarily by:

•

An $87 million increase caused by foreign exchange impacts

•

A $42 million increase resulting from the favorable resolution of various project contingencies and ad valorem tax issues in the 2003 period

•

A $13 million increase associated with the business expansion projects placed in service

•

Cost increases of $28 million, including depreciation and processing plant maintenance activity in Canada

•

A $60 million decrease as a result of operations sold in 2003

•

A $42 million decrease in gas purchases for distribution, due primarily to reduced volumes partly offset by higher commodity costs

•

An $18 million decrease due to severance costs in the 2003 period

•

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

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

•

A $77 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, Alliance Pipeline and the Aux Sable liquids plant in April 2003, and Foothills Pipe Lines Ltd in August 2003

•

An $18 million decrease in equity earnings as a result of investments sold in 2003

•

An increase of $12 million in equity earnings of Gulfstream Natural Gas System, resulting from higher revenues and volumes due to fuel switching during the unusually active hurricane season in Florida.

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 recorded in the prior year and higher operating expenses such as depreciation. 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 September 30,								Nine Months Ended September 30,
(in millions, except where noted)	2004			2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	2,506		$	2,076	$	430		$	7,207	$	6,643	$	564
Operating expenses		2,380			2,009		371			6,824		6,476		348
Gains on sales of other assets, net		1			—		1			1		—		1

Operating income		127			67		60			384		167		217
Other income, net of expenses		(16	)		14		(30	)		17		53		(36	)
Minority interest expense		44			30		14			148		84		64

EBIT	$	67		$	51	$	16		$	253	$	136	$	117

Natural gas gathered and processed/transported, TBtu/d ^a		7.4			7.5		(0.1	)		7.3		7.5		(0.2	)
NGL production, MBbl/d ^b		371			354		17			363		355		8
Average natural gas price per MMBtu ^{c, d, e}	$	5.76		$	4.97	$	0.79		$	5.81	$	5.66	$	0.15
Average NGL price per gallon ^{d, e}	$	0.72		$	0.49	$	0.23		$	0.64	$	0.52	$	0.12

^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 September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $315 million increase due to higher average NGL prices

•

A $155 million increase due to higher average natural gas prices

•

A $20 million increase was attributable to a $13.69 per barrel increase in average condensate prices to $43.88 for the three months ended September 30, 2004 from $30.19 for the same period in 2003

•

A $4 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts

•

A $30 million decrease related primarily to lower NGL and natural gas sales volumes partially offset by an increase related to wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips

•

A $26 million decrease related to cash flow hedging, which reduced revenues by approximately $65 million for the three months ended September 30, 2004 and by $39 million for the three months ended September 30, 2003

•

An $8 million decrease from trading and marketing net margin primarily due to natural gas asset based trading and marketing.

Operating Expenses. The increase was driven primarily by:

•

A $370 million increase due to higher average costs of raw natural gas supply which is primarily due to an increase in average NGL and natural gas prices

•

A $22 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets

•

A $15 million decrease primarily related to lower purchased raw natural gas supply partially offset by the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips

•

A $5 million increase in operating and general and administrative expenses, due to the timing of repairs and maintenance and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips

Other Income, Net of Expenses. The decrease was driven primarily by:

•

A $23 million impairment charge related to management’s assessment of the recoverability of some equity method investments

•

A $7 million decrease in earnings from equity method investments, primarily the result of an asset impairment and other charges recorded by an equity method investment in the third quarter of 2004

Minority Interest Expense. Minority interest expense increased due to increased earnings from Duke Energy Field Services LLC (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 Duke Capital that are not included in DEFS’ results.

EBIT. The increase in EBIT resulted primarily from the favorable effects of commodity prices partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices was not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The increase was driven primarily by:

•

A $505 million increase due to higher average NGL prices

•

A $95 million increase due to higher average natural gas prices

•

A $29 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing

•

A $25 million increase was attributable to a $8.13 per barrel increase in average condensate prices to $39.12 for the nine months ended September 30, 2004 from $30.99 for the same period in 2003

•

A $19 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts

•

A $110 million decrease from lower NGL and raw natural gas sales volume, partially offset by an increase related to wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips

•

A $2 million decrease related to cash flow hedging, which reduced revenues by approximately $160 million for the nine months ended September 30, 2004 and by $158 million for the nine months ended September 30, 2003.

Operating Expenses. The increase was driven primarily by:

•

A $435 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices

•

A $22 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets

•

A $90 million decrease related primarily to lower purchased raw natural gas supply volume partially offset by the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips

•

A $10 million decrease in operating, and general and administrative expenses, due to the lower repairs, maintenance and environmental expenses, partially offset by an increase related to the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips.

Other Income, Net of Expenses. The decrease was driven primarily by:

•

A $23 million impairment charge related to management’s assessment of the recoverability of some equity method investments

•

A $13 million decrease due to the sale of equity method investments in 2003.

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 resulted primarily from the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

Duke Energy North America ^a


	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions, except where noted)	2004			2003			Increase (Decrease)			2004			2003			Increase (Decrease)
Operating revenues	$	542		$	1,141		$	(599	)	$	1,812		$	3,499		$	(1,687	)
Operating expenses		547			1,517			(970	)		2,062			3,844			(1,782	)
Losses on sales of other assets, net		(6	)		(84	)		78			(374	)		(84	)		(290	)

Operating loss		(11	)		(460	)		449			(624	)		(429	)		(195	)
Other income, net of expenses		7			11			(4	)		5			207			(202	)
Minority interest expense (benefit)		13			(38	)		51			(7	)		(45	)		38

EBIT	$	(17	)	$	(411	)	$	394		$	(612	)	$	(177	)	$	(435	)

Actual plant production, GWh ^b,c		7,213			9,130			(1,917	)		17,596			18,750			(1,154	)
Proportional megawatt capacity in operation											9,890			15,836			(5,946	)

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

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

^c	Gigawatt-hours

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

Operating Revenues. The decrease was driven primarily by:

•

A $565 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 $25 million from higher average natural gas prices realized in the current quarter.

•

An $85 million decrease from lower power generation volumes, due primarily to the sale of the southeast region plants and overall lower sales

•

An $80 million reduction in revenues from lower average realized power prices, primarily as a result of the losses from some DENA power sales contracts

•

$108 million in higher net trading margins. In 2004, DENA recognized $47 million positive net trading margins.

Operating Expenses. The decrease was driven primarily by:

•

A $555 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 $40 million from higher average natural gas prices in the current quarter.

•

A $254 million decrease from the impairment of goodwill in 2003

•

$90 million of lower plant fuel costs, due to reduced volumes driven by the sale of the southeast region plants and overall lower plant production

•

A $39 million in lower general and administrative expenses, primarily from a 2003 $28 million CFTC settlement ($17 million net of minority interest expense) and 2003 severance costs of $5 million

•

A $26 million decrease in operations and maintenance expense, due primarily to the sale of the southeast region plants, overall lower plant production, and reduced cost from renegotiated outsourcing agreements

•

$24 million in lower depreciation expense due primarily to the sale of the southeast region plants

Losses on Sales of Other Assets, net. The decrease was driven primarily by the 2003 $84 million loss associated with the write-down of DENA’s 25% interest in the Vermillion plant, other turbines and equipment to their estimated fair value.

Minority Interest Expense (Benefit). Minority interest expense increased due primarily to more favorable 2004 results at DETM as compared to 2003, as a result of the DETM wind-down of operations.

EBIT. EBIT primarily increased as a result of lower plant depreciation and operating costs from the sale of the southeast region plants in 2004, in addition to the goodwill impairment, CFTC settlement, and severance accrual recorded in 2003. DENA’s future results of operations may not realize the full impact of commodity market price changes as certain of DENA’s future generation sales volumes and fuel purchases are contracted under fixed price arrangements.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $1,375 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 $80 million decrease in natural gas sales realized

•

$62 million in lower net trading margins. In 2004, DENA recognized $24 million negative net trading margins.

•

A $25 million decrease from lower power generation volumes, due primarily to the sale of the southeast region plants. In addition, there was an approximate $135 million reduction in revenues from lower average realized power prices, primarily as a result of the losses from some DENA power sales contracts.

Operating Expenses. The decrease was driven primarily by:

•

A $1,395 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 $75 million decrease in natural gas purchase costs.

•

$145 million of higher plant fuel costs due to overall higher average realized natural gas prices in the current year, due primarily to lower value realized from financial gas hedges. This increase was partially offset by an approximate $70 million reduction in plant fuel costs due to lower volumes primarily driven by the sale of the southeast region plants.

•

A $14 million decrease in operations and maintenance expense, due primarily to the sale of the southeast region plants, partially offset by two plants entering into commercial operation late in the second quarter of 2003 and reduced cost from renegotiated outsourcing agreements

•

$51 million of lower depreciation expense, primarily due to sale of the southeast region plants

•

A $254 million decrease from the impairment of goodwill in 2003

•

$60 million of lower general and administrative expense, primarily from a 2003 $28 million CFTC settlement ($17 million net of minority interest expense) and 2003 severance costs of $5 million. The impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower bad debt expense also contributed to the lower general and administrative expense.

•

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 $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)

Losses on Sales of Other Assets, net. Losses on sales of other assets for the nine months ended September 30, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the sale of DENA’s southeastern plants. (See Note 7 to the Consolidated Financial Statements.) This was partially offset by the 2003 $84 million loss associated with the write-down of DENA’s 25% interest in the Vermillion plant, turbines and other equipment to their estimated fair value.

Other Income, net of expenses. The decrease in other income, net of expenses was due primarily to the $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel and the associated foregone equity earnings of $22 million.

Minority Interest Expense (Benefit). Minority interest benefit decreased due primarily to more favorable 2004 results at DETM as compared to 2003 as a result of the DETM wind-down of operations.

EBIT. EBIT decreased primarily as a result of the increased losses from dispositions and reduced gross margin from lower net sales, values realized from hedge positions, and mark-to-market earnings as outlined above. These decreases were partially offset by decreased plant depreciation and operating cost from the 2004 sale of the southeast region plants and the prior year goodwill impairment. DENA’s future results of operations may not realize the full impact of commodity market price changes as certain of DENA’s future generation sales volumes and fuel purchases are contracted under fixed price arrangements.

International Energy


	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions, except where noted)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	146	$	151	$	(5	)	$	447	$	492	$	(45	)
Operating expenses		109		114		(5	)		338		339		(1	)
Gains on sales of other assets, net		1		1		—			1		2		(1	)

Operating income		38		38		—			110		155		(45	)
Other income, net of expenses		29		9		20			60		31		29
Minority interest expense		3		3		—			9		11		(2	)

EBIT	$	64	$	44	$	20		$	161	$	175	$	(14	)

Sales, GWh		4,277		3,936		341			13,088		12,352		736
Proportional megawatt capacity in operation									4,136		4,041		95

Three

Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $14 million decrease in revenues in Guatemala and El Salvador due to decreased cross border power marketing activity

•

A $9 million increase from contracted sales due to an additional 80 megawatts of plant capacity becoming operational at Planta Arizona in Guatemala

Operating Expenses. The decrease was driven primarily by:

•

A $13 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity

•

A $7 million decrease in Brazil environmental reserve

•

An $11 million increase in Peru power purchases due to unfavorable hydrological conditions

•

A $5 million increase due to higher generation from the additional 80 megawatts at Planta Arizona in Guatemala as described above

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

•

An $8 million increase due to favorable netback pricing at National Methanol due to stronger methyl tertiary butyl ether (MTBE) prices

•

A $7 million increase in Brazil due to a purchase accounting adjustment recorded in 2003

EBIT. The increase in EBIT was due primarily to a reduction in environmental reserves in Brazil and improved results from National Methanol as discussed above.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The decrease was driven primarily by:

•

A $37 million decrease in revenues in Guatemala and El Salvador due to decreased cross border power marketing activity

•

A $33 million decrease in natural gas sales due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003

•

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

•

A $24 million increase due to the commencement of operations at Planta Arizona in Guatemala

•

A $23 million increase resulting from higher sales prices and volumes realized from contracts in Brazil

•

A $9 million increase in revenues due to favorable hydrological conditions in Peru

Operating Expenses. There was no significant variance; however, the following items impacted operating expenses:

•

A $36 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003

•

A $34 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity

•

A $19 million increase due to the commencement of operations at Planta Arizona in Guatemala

•

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 $15 million increase in Peru power purchases due to unfavorable hydrological conditions

•

A $13 million increase due primarily to increased transmission fees and other costs in Brazil

•

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

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

•

A net $11 million increase due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment and disposition of the investment in 2004

•

A $7 million increase in Brazil due to a purchase accounting adjustment recorded in 2003

•

A $5 million increase due to favorable netback pricing at National Methanol

EBIT. The decrease in EBIT was due to a variety of factors, with primary drivers consisting of decreases from the charge associated with the disposition of the ownership share in the Cantarell facility, the benefits recorded in 2003 relating to a regulatory audit in Brazil and the termination of a liquefied natural gas business contract, partially offset by increases due to a reduction in environmental reserves in Brazil in 2004, favorable netback pricing at National Methanol due to stronger MTBE prices, better results from Planta Arizona in Guatemala and exchange rates in Brazil.

Crescent


	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2004		2003		Increase (Decrease)			2004		2003		Increase (Decrease)
Operating revenues	$	77	$	44	$	33		$	216	$	141	$	75
Operating expenses		62		41		21			173		126		47
Gains on sales of investments in commercial and multi-family real estate		28		36		(8	)		149		47		102

Operating income		43		39		4			192		62		130
Minority interest expense		—		—		—			2		1		1

EBIT	$	43	$	39	$	4		$	190	$	61	$	129

Three

Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The increase was driven primarily by a $37 million increase in residential developed lot sales, including increased sales at the Lake Keowee projects in northwestern South Carolina and the Palmetto Bluff project in Bluffton, South Carolina.

Operating Expenses. The increase was driven primarily by a $17 million increase in the cost of residential developed lot sales due to increased sales at the projects noted above.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by a $20 million decrease in land management or “legacy” land sales due to large sales in the prior year quarter of the Anthony and SouthPoint tracts, offset by a $12 million increase in net commercial project sales, representing the sale of four commercial projects in the current year quarter compared to the sale of one commercial project in the prior year quarter.

EBIT. As discussed above, the increase in EBIT was driven primarily by an increase in residential developed lot sales and commercial project sales, offset by a decrease in land management or “legacy” land sales.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003

Operating Revenues. The increase was driven primarily by an $82 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.

Operating Expenses. The increase was driven primarily by a $48 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 $33 million increase in commercial project sales, representing the sale of a commercial project in the Washington, D.C. area in March 2004 and the sales of four smaller commercial projects in the current year third quarter, compared to one commercial project sale in the prior year

•

A $47 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 $23 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 an increase in residential developed lot sales and commercial project sales, the sale of the Alexandria land tract in the Washington, D.C. area and an increase in “legacy” land sales.

Other

EBIT for Other increased $36 million for the three months and $41 million for the nine months ended September 30, 2004, compared to the same periods in 2003, due primarily to charges of $25 million in 2003 related to severance. Also contributing to the increase in EBIT was lower governance costs in 2004 due to cost reductions and cost shifts from corporate to business units.

Additionally for the nine months ended September 30, 2004, lower deferred profit from D/FD related to eliminations in Other in the prior year not occurring in 2004 as a result of the wind down of D/FD.

Duke Capital has a wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), that provides insurance coverage to Duke Capital affiliates as well as to certain third parties on a limited basis. Additionally, Bison has obtained reinsurance coverage from third party insurance providers for insured events over certain per incident deductibles. As a result of the Moss Bluff storage field fire during the third quarter of 2004, Bison incurred net charges of approximately $12 million for property insurance coverage and general liability coverage for the incident.

Other Impacts on Net (Loss) Income

Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Capital. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No.150. As a result of this accounting change, minority interest expense decreased $33 million for the nine months ended September 30, 2004.

Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of Duke Capital’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures. Total minority interest expense related to the joint ventures (including the portion related to interest and taxes) increased $72 million for the three months and $107 million for the nine months ended September 30, 2004, compared to the same periods in 2003. The change was driven by improved results at DEFS and DETM.

The effective income tax rates for the three and nine months ended September 30, 2004, compared to the same periods in 2003 increased as a result of $1,030 million of tax expense from the change in deferred taxes as a result of the Duke Energy Americas, LLC reorganization, the flow through of income tax benefits to Duke Energy partially offset by the reduction of $45 million of state and federal income tax reserves (See Note 15 to the Consolidated Financial Statements for additional information).

The decrease in income from discontinued operations for the three months ended September 30, 2004, compared to the same period in 2003, was due primarily to the $52 million tax benefit recorded in the third quarter of 2003 related to the goodwill impairment recognized in 2002 for the gas trading business in Europe. The increase in income from discontinued operations for the nine months ended September 30, 2004, compared to the same period in 2003 was due primarily to a $273 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, partially offset by the $52 million tax benefit noted above and lower earnings.

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 SFAS No. 143, “Accounting for Asset Retirement Obligations.”

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities increased $678 million for the nine months ended September 30, 2004, compared to the same period in 2003, due primarily to higher cash settlements from trading and marketing activities and an increase in cash provided from changes working capital. The increase in cash provided from working capital was due primarily to an increase in cash provided by current liabilities, partially offset by a decrease in cash provided by receivables attributable to the contraction of the business at DENA in 2003.

Investing Cash Flows

Net cash provided by investing activities increased $403 million for the nine months ended September 30, 2004, compared to the same period in 2003. Of this increase, $318 million related 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 2004 period and $399 million relates to decreased capital expenditures at DENA and Natural Gas Transmission partially offset by increased commercial and multi-family real estate capital expenditures at Crescent. These increases were partially offset by a $260 million decrease in net proceeds received from the sales of equity investments and other assets, primarily related to sales in the 2003 period of DENA’s 50% ownership interest in Duke/UAE Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline and its investment in the Alliance Pipeline and Foothills Pipe Lines Ltd.; Field Services’ sale of certain gathering pipelines and gas processing plants; Duke Capital’s sale of the TEPPCO class B units; and the monetization of various investments at Duke Capital Partners LLC, which were partially offset by the sale of International Energy’s Asia-Pacific power generation and natural gas transmission businesses and DENA’s sale of its southeastern plants, in the 2004 period.

Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $319 million for the nine months ended September 30, 2004, compared to the same period in 2003. This change was due primarily to approximately $1.4 billion of higher redemptions and net paydowns of long-term debt, commercial paper and notes payable in 2003 as compared to 2004. Partially offsetting this change were capital contributions of approximately $1.0 billion for the nine months ended September 30, 2003. Total debt reductions of approximately $1.7 billion in 2004 consisted of approximately $860 million in net cash redemptions (see Note 4 to the Consolidated Financial Statements for more information) 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 was placed in trust and fully funded in connection with the closing of the sale transaction and repaid in September 2004. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific operations.

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.

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 September 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 November 1, 2004 credit ratings from the agencies retained by Duke Capital to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of November 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 September 30, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $300 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 September 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 September 30, 2004, Duke Capital and its subsidiaries had effective SEC shelf registrations for up to $1,092 million in gross proceeds from debt and other securities. This represents an increase of approximately $92 million as compared to December 31, 2003, providing future funding flexibility. Additionally, as of September 30, 2004, Duke Capital had access to 900 million Canadian dollars (U.S. $707 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 September 30, 2004:

Revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” In December 2003, the Financial Accounting Standards Board (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

•

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

As disclosed in Note 5 to the Consolidated Financial Statements, in October 2004 Duke Energy, the parent of Duke Capital, made voluntary contributions of $250 million to its U.S. defined benefit retirement plan.

In October 2004, the American Jobs Creation Act of 2004 (the Act) was signed into law. The Act creates a temporary incentive for U.S. entities with foreign earnings to repatriate accumulated foreign earnings, subject to certain limitations, by providing an 85% dividends received deduction for certain repatriated earnings. Duke Energy currently anticipates repatriating approximately $500 million of accumulated foreign earnings in 2005. Duke Capital does not anticipate any material tax expense as a result of the Act, however, Duke Energy anticipates recording approximately $45 million of tax expense in the fourth quarter of 2004. Additionally, the Act establishes a deduction for certain qualified domestic production activities, such as gas extraction and electric production. The FASB is currently considering whether to provide guidance on accounting for the qualified domestic production activities deduction. Therefore, it is currently uncertain how this deduction under the Act will impact the Duke Capital consolidated financial statements.

For information on subsequent events related to debt and credit facilities and preferred and preference stock, see Note 4 to the Consolidated Financial Statements. For information on subsequent events related to litigation and contingencies, see Note 12 to the Consolidated Financial Statements. For information on the subsequent sale of the Moapa facility, see Note 8 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 $930 million as of September 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 $850 million as of September 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)


	September 30, 2004 One-Day Impact on Operating Income for 2004 ^a	Estimated Average One- Day Impact on Operating Income for 3^rd Quarter 2004 ^a	Estimated Average One- Day Impact on Operating Income for the Year 2003 ^a	High One-Day Impact on Operating Income for 3^rd Quarter 2004 ^a	Low One-Day Impact on Operating Income for 3^rd Quarter 2004 ^a
Calculated DER	$8	$7	$6	$11	$5

^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 the 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. Because of this identified reportable condition and Duke Capital’s ongoing evaluation of internal controls over financial reporting, 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 third 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 June 30, 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.

In July 2003, a fire occurred at the Moss Landing Power Plant in California, operated by Duke Energy Moss Landing LLC (DEML), a subsidiary of Duke Energy North America, when fuel oil was ignited by a contractor performing tank clean out and dismantling activities. The Monterey County District Attorney initiated civil enforcement action against DEML alleging violations of the California Health and Safety Code and the Business and Professions Code. The alleged violations concern the handling of hazardous materials at the site and unlawful release of hazardous materials into the environment. DEML denied the allegations but agreed to settle the civil enforcement action by committing to expend a total of $752,287, the majority of which entails reimbursement of costs to the County and safety/environmental training efforts by the company, but also includes a $100,000 civil penalty payment. The District Attorney’s office also entered into a settlement of a related action against DEML’s contractor for alleged violations in the incident. Both settlements were announced on September 22, 2004.

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

(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		Third Amendment to Parent Company Agreement among Duke Energy Field Services Corporation, Duke Energy Field Services, LLC, ConocoPhillips Company and Duke Energy Corporation dated as of July 29, 2004 (filed with the Quarterly Report on Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2004, File No. 1-4928, as exhibit 10-1).

10.2		Second Amendment to Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC dated as of July 29, 2004 (filed with the Quarterly Report on Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2004, File No. 1-4928, as exhibit 10-4).

*18.1		Letter re: Change in Accounting Principle

*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.

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: November 15, 2004		/s/ David L. Hauser
		David L. Hauser
		President

Date: November 15, 2004		/s/ Keith G. Butler
		Keith G. Butler
		Chief Financial Officer and Controller