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 1-4928

DUKE ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

North Carolina	56-0205520
(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 x No ¨

Indicate the number of shares outstanding of each of the Issuer’s classes of common stock, as of the latest practicable date.

Number of shares of Common Stock, without par value, outstanding as of October 29, 2004…937,955,726

DUKE ENERGY CORPORATION

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		44
3.	Quantitative and Qualitative Disclosures About Market Risk		68
4.	Controls and Procedures		69
	PART II. OTHER INFORMATION
1.	Legal Proceedings		70
2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		70
4.	Submission of Matters to a Vote of Security Holders		70
6.	Exhibits		71
	Signatures		72

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Duke Energy Corporation’s 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 Energy’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 Energy’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

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

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

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

• The weather and other natural phenomena

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

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• 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 Energy and its subsidiaries are subject or other external factors over which Duke Energy has no control

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

• Lack of improvement or declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy’s defined benefit pension plans

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

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

• Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power, pipeline, gathering, liquefied 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 Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)

	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	$	3,491		$	3,572		$	10,310		$	10,947
Regulated electric		1,431			1,387			3,954			3,788
Regulated natural gas		585			590			2,202			2,105
Total operating revenues		5,507			5,549			16,466			16,840
Operating Expenses
Natural gas and petroleum products purchased		2,616			2,749			8,167			8,878
Operation, maintenance and other		826			964			2,439			2,515
Fuel used in electric generation and purchased power		530			695			1,699			1,612
Depreciation and amortization		525			473			1,379			1,341
Property and other taxes		133			127			411			400
Impairment and other related charges		22			—			25			—
Impairment of goodwill		—			254			—			254
Total operating expenses		4,652			5,262			14,120			15,000
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		28			36			149			47
Losses on Sales of Other Assets, net		(4	)		(79	)		(353	)		(76	)
Operating Income		879			244			2,142			1,811
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		33			35			110			85
(Losses) gains on sales and impairments of equity investments		(14	)		33			(14	)		266
Other income and expenses, net		35			35			107			121
Total other income and expenses		54			103			203			472
Interest Expense		342			375			1,035			1,027
Minority Interest Expense (Benefit)		61			(11	)		142			89
Earnings (Loss) From Continuing Operations Before Income Taxes		530			(17	)		1,168			1,167
Income Tax Expense (Benefit) from Continuing Operations		129			(22	)		296			368
Income From Continuing Operations		401			5			872			799
Discontinued Operations
Net operating (loss) income, net of tax		(11	)		8			(8	)		27
Net (loss) gain on dispositions, net of tax		(1	)		36			268			34
(Loss) Income From Discontinued Operations		(12	)		44			260			61
Income Before Cumulative Effect of Change in Accounting Principle		389			49			1,132			860
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			—			—			(162	)
Net Income		389			49			1,132			698
Dividends and Premiums on Redemption of Preferred and Preference Stock		2			3			7			13
Earnings Available For Common Stockholders	$	387		$	46		$	1,125		$	685
Common Stock Data
Weighted-average shares outstanding
Basic		938			905			925			901
Diluted		940			907			928			902
Earnings per share (from continuing operations)
Basic	$	0.42		$	—		$	0.94		$	0.87
Diluted	$	0.42		$	—		$	0.93		$	0.87
(Loss) Earnings per share (from discontinued operations)
Basic	$	(0.01	)	$	0.05		$	0.28		$	0.07
Diluted	$	(0.01	)	$	0.05		$	0.28		$	0.07
Earnings per share (before cumulative effect of change in accounting principle)
Basic	$	0.41		$	0.05		$	1.22		$	0.94
Diluted	$	0.41		$	0.05		$	1.21		$	0.94
Earnings per share
Basic	$	0.41		$	0.05		$	1.22		$	0.76
Diluted	$	0.41		$	0.05		$	1.21		$	0.76
Dividends per share	$	—		$	—		$	0.825		$	0.825

See Notes to Consolidated Financial Statements.

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	September 30, 2004		December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	2,858	$	1,160
Receivables (net of allowance for doubtful accounts of $230 at September 30, 2004 and $280 at December 31, 2003)		2,720		2,890
Inventory		894		941
Assets held for sale		125		424
Unrealized gains on mark-to-market and hedging transactions		1,207		1,566
Other		844		694
Total current assets		8,648		7,675
Investments and Other Assets
Investments in unconsolidated affiliates		1,294		1,398
Nuclear decommissioning trust funds		1,262		925
Goodwill		4,002		3,962
Notes receivable		225		260
Unrealized gains on mark-to-market and hedging transactions		1,666		1,857
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		776		1,117
Total investments and other assets		10,741		12,294
Property, Plant and Equipment
Cost		45,908		46,009
Less accumulated depreciation and amortization		13,052		12,139
Net property, plant and equipment		32,856		33,870
Regulatory Assets and Deferred Debits
Deferred debt expense		303		275
Regulatory assets related to income taxes		1,203		1,152
Other		988		939
Total regulatory assets and deferred debits		2,494		2,366
Total Assets	$	54,739	$	56,205

See Notes to Consolidated Financial Statements.

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	September 30, 2004		December 31, 2003
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,742	$	2,317
Notes payable and commercial paper		225		130
Taxes accrued		380		14
Interest accrued		304		304
Liabilities associated with assets held for sale		41		651
Current maturities of long-term debt		3,327		1,200
Unrealized losses on mark-to-market and hedging transactions		1,040		1,283
Other		1,671		1,799
Total current liabilities		8,730		7,698
Long-term Debt, including debt to affiliates of $876 at December 31, 2003		17,101		20,622
Deferred Credits and Other Liabilities
Deferred income taxes		4,784		4,120
Investment tax credit		156		165
Unrealized losses on mark-to-market and hedging transactions		1,266		1,754
Liabilities associated with assets held for sale		14		737
Other		5,679		5,526
Total deferred credits and other liabilities		11,899		12,302
Commitments and Contingencies
Minority Interests		1,587		1,701
Preferred and preference stock without sinking fund requirements		134		134
Common Stockholders’ Equity
Common stock, no par, 2 billion shares authorized; 938 million and 911 million shares outstanding at September 30, 2004 and December 31, 2003, respectively		10,493		9,519
Retained earnings		4,435		4,060
Accumulated other comprehensive income		360		169
Total common stockholders’ equity		15,288		13,748
Total Liabilities and Common Stockholders’ Equity	$	54,739	$	56,205

See Notes to Consolidated Financial Statements.

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DUKE ENERGY CORPORATION

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 income	$	1,132		$	698
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		1,524			1,493
Cumulative effect of change in accounting principle		—			162
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		115			(170	)
Impairment of goodwill		—			254
Deferred income taxes		661			116
Purchased capacity levelization		93			143
Contribution to company sponsored pension plan		(14	)		(181	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		198			12
Receivables		234			1,025
Inventory		55			(182	)
Other current assets		(65	)		(32	)
Increase (decrease) in
Accounts payable		(667	)		(926	)
Taxes accrued		242			392
Other current liabilities		96			(135	)
Capital expenditures for residential real estate		(218	)		(136	)
Cost of residential real estate sold		127			78
Other, assets		(306	)		(296	)
Other, liabilities		365			222
Net cash provided by operating activities		3,423			2,490
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net of refund		(1,745	)		(1,940	)
Net proceeds from the sales of equity investment and other assets, and sales of and collections on notes receivable		1,231			1,540
Proceeds from the sales of commercial and multi-family real estate		413			95
Other		(119	)		(134	)
Net cash used in investing activities		(220	)		(439	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the
Issuance of long-term debt		166			2,819
Issuance of common stock and common stock related to employee benefit plans		948			214
Payments for the redemption of
Long-term debt		(1,735	)		(1,577	)
Guaranteed preferred beneficial interests in subordinated notes		—			(250	)
Preferred stock of a subsidiary		(76	)		(38	)
Notes payable and commercial paper		85			(1,468	)
Distributions to minority interests		(1,094	)		(2,067	)
Contributions from minority interests		959			1,958
Dividends paid		(798	)		(786	)
Other		2			21
Net cash used in financing activities		(1,543	)		(1,174	)
Changes in cash and cash equivalents associated with assets held for sale		38			—
Net increase in cash and cash equivalents		1,698			877
Cash and cash equivalents at beginning of period		1,160			874
Cash and cash equivalents at end of period	$	2,858		$	1,751
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					1,200
Reclassification of long-term debt to notes payable and commercial paper					1,000

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is a leading energy company located in the Americas with a real estate subsidiary. The Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. The Consolidated Financial Statements also reflect Duke Energy’s 12.5% undivided interest in the Catawba Nuclear Station.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present Duke Energy’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 Energy’s Form 10-K/A for the 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 31^st 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 Energy’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 Energy’s Form 10-K/A for the year ended December 31, 2003, as of January 1, 2003, Duke Energy 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 Energy 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 Energy’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 Energy 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

5

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 $2,721 million to $2,490 million, and net cash used in investing activities decreased by $231 million, from $670 million to $439 million, in the September 30, 2003 Consolidated Statement of Cash Flows.

Also in Duke Energy’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 $5,603 million to $5,549 million, for the three months and $94 million, from $16,934 million to $16,840 million, for the nine months ended September 30, 2003. Also as a result of this change, total operating expenses decreased by $18 million, from $5,280 million to $5,262 million, for the three months and $47 million, from $15,047 million to $15,000 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. Earnings Per Common Share

Basic earnings per share are computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share are computed by dividing earnings available for common stockholders by the diluted weighted-average number of common shares outstanding during the period. Diluted earnings per share reflect the potential dilution that could occur if securities or other agreements to issue common stock which have met market price or other contingencies (such as stock options, equity units, stock-based performance unit awards, convertible debt and phantom stock awards) were exercised or converted into common stock. The following table reconciles the weighted-average shares outstanding to the diluted weighted-average shares outstanding.

Weighted-Average Shares Outstanding (in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Weighted-average shares outstanding	938	905	925	901
Potential dilution for the period	2	2	3	1
Diluted weighted-average shares outstanding	940	907	928	902

The increase in weighted-average shares outstanding for the three and nine-month periods ended September 30, 2004, compared to the same periods in 2003, was due primarily to the issuance of 22.5 million shares in connection with the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May 2004. For further information see Note 5.

Options, restricted stock, performance and phantom stock awards to purchase approximately 24 million shares as of September 30, 2004 and 28 million shares as of September 30, 2003 were not included in

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“potential dilution for the period” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

Duke Energy’s $750 million of Equity Units, which will result in an issuance of approximately 19 million shares in November 2004, is not included in “potential dilution for the period” in the above table because their inclusion would be antidilutive. These Equity Units are antidilutive under the treasury stock method of computing diluted earnings per share under SFAS No. 128, “Earnings Per Share,” since the average market price of Duke Energy’s common stock during all periods presented is less than the exercise price of the Equity Units. For further information see Note 5.

Additionally, Duke Energy’s $770 million convertible debt issuance, which is potentially convertible into approximately 33 million shares, is not included in “potential dilution for the period” in the above table because the market price and other contingencies for issuance had not been met as of September 30, 2004 and September 30, 2003. See Note 15 for discussion of the final consensus reached by the EITF regarding Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share,” and a discussion of the related anticipated impact of this security on diluted earnings per share.

3. Stock-Based Compensation

Duke Energy accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and 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 shows what earnings available for common stockholders, basic earnings per share and diluted earnings per share would have been if Duke Energy had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment to FASB Statement No. 123),” to all stock-based compensation awards.

Pro Forma Stock-Based Compensation (in millions, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Earnings available for common stockholders, as reported	$	387		$	46		$	1,125		$	685
Add: stock-based compensation expense included in reported net income, net of related tax effects		5			1			10			6
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(7	)		(7	)		(19	)		(25	)
Pro forma earnings available for common stockholders, net of related tax effects	$	385		$	40		$	1,116		$	666
Earnings per share
Basic – as reported	$	0.41		$	0.05		$	1.22		$	0.76
Basic – pro forma	$	0.41		$	0.04		$	1.21		$	0.74
Diluted – as reported	$	0.41		$	0.05		$	1.21		$	0.76
Diluted – pro forma	$	0.41		$	0.04		$	1.20		$	0.74

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4. 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
Materials and supplies	$	446	$	445
Natural gas and natural gas liquid products held in storage for transmission, processing, and sales commitments		329		299
Coal held for electric generation		80		87
Petroleum products		39		110
Total inventory	$	894	$	941

5. Debt and Credit Facilities and Preferred and Preference Stock of Duke Energy’s Subsidiaries

In February 2004, Duke Energy remarketed $875 million of senior notes due in 2006, underlying its 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 Energy 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 March 2004, Duke Energy redeemed the entire issue of its 7.20% debt due to an affiliate in 2037 for approximately $350 million, in connection with the redemption of its Duke Energy Capital Trust I 7.20% Cumulative Quarterly Income Preferred Securities due in 2037. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued and unpaid distributions to the redemption date.

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 Energy 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 Energy completed the sale of the Asia-Pacific assets, which includes substantially all of Duke Energy’s assets in Australia and New Zealand, to Alinta Ltd. on April 23, 2004.

In April 2004, Duke Capital LLC (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 May 2004, Duke Energy redeemed its Series C 6.60% senior notes due in 2038, at a $200 million face value. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued interest to the redemption date.

In May 2004, Duke Energy issued 22,449,000 shares of its common stock in the settlement of the forward purchase contract component of its Equity Units issued in March 2001. Under the terms of the contract, the Equity Unit holders were required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement with a floor and a ceiling. The rate was 0.6414 shares of stock per Equity Unit as the market price of settlement was below the floor.

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In June 2004, Duke Energy redeemed the entire issue of its 7.20% debt due to an affiliate in 2039 for approximately $250 million, in connection with the redemption of its Duke Energy Capital Trust II 7.20% 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 August 2004, Duke Energy redeemed the entire issue of its 8 3/8% debt due to an affiliate in 2029 for $250 million, in connection with the redemption of its Duke Capital Financing Trust III 8 3/8% 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% Equity Units scheduled for November 16, 2004.

On October 27, 2004, Duke Energy 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 $830 million compared to December 31, 2003, primarily relating to the divested Australian operations as discussed in Note 9. In addition, Duke Energy, Duke Capital, Duke Energy Field Services, LLC (DEFS), Westcoast Energy Inc. 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 Energy’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 Energy 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.

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

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

		Credit Facilities Capacity		Amounts Outstanding
	Expiration Date			Commercial Paper		Letters of Credit		Total
Duke Energy
$150 two-year bilateral a, b	September 2005
$500 three-year syndicated a, b	June 2007
Total Duke Energy		$	650	$	334	$	—	$	334
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		$	2,572	$	334	$	739	$	1,073

^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 Energy’s Subsidiaries. On June 1, 2004, Westcoast Energy, Inc. (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.

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6. Employee Benefit Obligations

The following table shows the components of the net periodic pension costs for Duke Energy’s U.S. retirement plan and Westcoast’s Canadian retirement plans.

Components of Net Periodic Pension Costs (Income) (in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Duke Energy U.S.
Service cost	$	16		$	18		$	48		$	53
Interest cost on projected benefit obligation		40			44			120			132
Expected return on plan assets		(59	)		(59	)		(175	)		(177	)
Amortization of prior service cost		—			(1	)		(1	)		(3	)
Amortization of net transition asset		(1	)		(1	)		(3	)		(3	)
Amortization of loss		4			—			11			—
Curtailment gain		—			—			(1	)		—
Net periodic pension costs (income)	$	—		$	1		$	(1	)	$	2
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 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 contributed approximately $11 million to the Westcoast plans in 2003.

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The following table shows the components of the net periodic post-retirement benefit costs for the Duke Energy U.S. and Westcoast plans.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Duke Energy U.S.
Service cost benefit	$	1		$	1		$	4		$	4
Interest cost on accumulated post- retirement benefit obligation		11			13			36			39
Expected return on plan assets		(5	)		(5	)		(14	)		(16	)
Amortization of net transition liability		4			5			12			14
Amortization of loss		2			1			7			3
Net periodic post-retirement benefit costs	$	13		$	15		$	45		$	44
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

In May 2004, the FASB staff issued FASB Staff Position (FSP) 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. The FSP provides guidance on the accounting for the subsidy. Duke Energy adopted this FSP and retroactively applied this FSP as of the date of issuance, impacting the three and nine month period results for its U.S. plan. As a result of anticipated prescription drug subsidy, the accumulated post-retirement benefit obligation for its U.S. plan decreased by $96 million. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $4 million for the three months and $8 million for the nine months ended September 30, 2004.

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7. Comprehensive Income and Accumulated Other Comprehensive Income

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

Total Comprehensive Income (in millions)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2004		2003			2004			2003
Net Income	$	389	$	49		$	1,132		$	698
Other comprehensive income
Foreign currency translation adjustments		247		294			(37	)		698
Net unrealized gains (losses) on cash flow hedges a		89		(111	)		268			306
Reclassification into earnings from cash flow hedges b		14		(40	)		(40	)		(147	)
Other comprehensive income, net of tax		350		143			191			857
Total Comprehensive Income	$	739	$	192		$	1,323		$	1,555

^a Net unrealized gains (losses) on cash flow hedges, net of $76 million tax expense for the three months ended September 30, 2004, $90 million tax benefit for the three months ended September 30, 2003, $142 million tax expense for the nine months ended September 30, 2004, and $171 million tax expense for the nine months ended September 30, 2003.

^b Reclassification into earnings from cash flow hedges, net of $3 million tax benefit for the three months ended September 30, 2004, $6 million tax benefit for the three months ended September 30, 2003, $21 million tax benefit for the nine months ended September 30, 2004 and $89 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	$	315		$	298	$	(444	)	$	169
Other comprehensive income changes year-to-date (net of $121 tax expense)		(37	)		228		—			191
Balance as of September 30, 2004	$	278		$	526	$	(444	)	$	360

8. Acquisitions, Dispositions and Impairments

Acquisitions. Duke Energy 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.

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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 Energy 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 9, and sales by Crescent which are discussed separately below) resulted in approximately $674 million in proceeds, and net pre-tax losses of $353 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 Energy still owns the remaining 75% interest in the Vermillion facility.

• DENA’s merchant power generation business in the southeastern United States. Duke Energy 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 values 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 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.

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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 $97 million in net proceeds. Those sales resulted in net gains of $4 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, DukeSolutions Huntington Beach LLC, and Duke Energy Merchant LLC’s (DEM’s) 15% ownership interest in Caribbean Nitrogen Company in the first quarter of 2004. DEM also sold its refined products operation in the eastern United States during the third quarter of 2004.

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 Energy 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 Energy 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 Energy 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 Energy 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 Energy used a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis included the use of an appropriate discount rate, estimated

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future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporated current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices.

9. Assets Held for Sale and Discontinued Operations

Assets Held for Sale. In the first quarter of 2004, Duke Energy 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 Energy determined that it was likely a bid in excess of the originally determined fair value would be accepted.

In April 2004, Duke Energy 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 Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the Asia-Pacific operations. In September 2004, Duke Energy 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 5 for a discussion of the impact of this transaction to consolidated long-term debt.

On September 21, 2004 Duke Energy signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving will purchase Duke Energy’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 Energy 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 Energy 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

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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 8. 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)

^b 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.

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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, and excluding Bayside and some Crescent properties, the following are included in Discontinued Operations in the Consolidated Statements of Operations in the nine-month period ended September 30, 2003:

• Duke Energy Hydrocarbons LLC (sold in the first quarter of 2003) ^c

• Commercial and multi-family properties owned by Crescent (sold in the fourth quarter of 2003) ^c

^a As a result of Bayside being classified as an equity investment prior to April 1, 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.

^c For additional information related to the exit of those activities, see the Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K/A for the year ended December 31, 2003.

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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	$	8		$	3		$	5		$	(2	)	$	(52	)	$	50
Field Services		29		1			—			1			—			—			—
Crescent		2		—			—			—			—			—			—
Other		5		3			1			2			(23	)		(9	)		(14	)
Total consolidated	$	179	$	12		$	4		$	8		$	(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	$	25		$	2		$	23		$	(3	)	$	(52	)	$	49
Field Services		296		7			2			5			19			7			12
Crescent		4		—			—			—			—			—			—
Other		27		2			3			(1	)		(43	)		(16	)		(27	)
Total consolidated	$	878	$	34		$	7		$	27		$	(27	)	$	(61	)	$	34

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10. Business Segments

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

Beginning in 2004, Crescent, formerly part of Other Operations, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages “legacy” land holdings primarily in the southeastern and southwestern United States. All other entities previously part of Other Operations and now within Other still remain, primarily: DukeNet Communications LLC, DEM, Bison Insurance Company Limited (Bison) and Duke Energy’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 Energy’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 Energy, 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.

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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
Franchised Electric	$	1,413		$	6		$	1,419		$	453
Natural Gas Transmission		585			53			638			265
Field Services		2,530			(24	)		2,506			67
Duke Energy North America		506			36			542			(17	)
International Energy		146			—			146			64
Crescent		77			—			77			43
Total reportable segments		5,257			71			5,328			875
Other		250			45			295			(25	)
Eliminations		—			(116	)		(116	)		—
Interest expense		—			—			—			(342	)
Minority interest expense and other a		—			—			—			22
Total consolidated	$	5,507		$	—		$	5,507		$	530
Three Months Ended September 30, 2003
Franchised Electric	$	1,354		$	5		$	1,359		$	436
Natural Gas Transmission		590			51			641			280
Field Services		2,028			48			2,076			51
Duke Energy North America		1,097			44			1,141			(411	)
International Energy		151			—			151			44
Crescent		44			—			44			39
Total reportable segments		5,264			148			5,412			439
Other		302			70			372			(88	)
Eliminations		(17	)		(218	)		(235	)		—
Interest expense		—			—			—			(375	)
Minority interest expense and other a		—			—			—			7
Total consolidated	$	5,549		$	—		$	5,549		$	(17	)

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

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Business Segment Data (in millions)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings (Loss) from Continuing Operations before Income Taxes
Nine Months Ended September 30, 2004
Franchised Electric	$	3,901		$	17		$	3,918		$	1,215
Natural Gas Transmission		2,202			162			2,364			974
Field Services		7,170			37			7,207			253
Duke Energy North America		1,723			89			1,812			(612	)
International Energy		447			—			447			161
Crescent		216			—			216			190
Total reportable segments		15,659			305			15,964			2,181
Other		807			122			929			(56	)
Eliminations		—			(427	)		(427	)		—
Interest expense		—			—			—			(1,035	)
Minority interest expense and other a		—			—			—			78
Total consolidated	$	16,466		$	—		$	16,466		$	1,168
Nine Months Ended September 30, 2003
Franchised Electric	$	3,705		$	15		$	3,720		$	1,206
Natural Gas Transmission		2,105			196			2,301			1,009
Field Services		6,051			592			6,643			136
Duke Energy North America		3,309			190			3,499			(177	)
International Energy		492			—			492			175
Crescent		141			—			141			61
Total reportable segments		15,803			993			16,796			2,410
Other		1,054			197			1,251			(205	)
Eliminations		(17	)		(1,190	)		(1,207	)		—
Interest expense		—			—			—			(1,027	)
Minority interest expense and other a		—			—			—			(11	)
Total consolidated	$	16,840		$	—		$	16,840		$	1,167

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

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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
Franchised Electric	$	16,455		$	16,088
Natural Gas Transmission		16,589			16,384
Field Services		6,539			6,417
Duke Energy North America		7,350			9,184
International Energy		3,331			4,550
Crescent		1,576			1,653
Total reportable segments		51,840			54,276
Other		3,232			2,585
Eliminations a		(333	)		(656	)
Total consolidated assets	$	54,739		$	56,205

^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.

11. Risk Management Instruments

The following table shows the carrying value of Duke Energy’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	$	795		$	424
Trading		72			177
Undesignated		(300	)		(215	)
Total	$	567		$	386

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 Energy’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 Energy’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 six years.

The $371 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 $85 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

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and deferred western plants along with settlements of net mark-to-market gains during the nine months ended September 30, 2004, partially offset by other activity.

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

Fair value of contracts outstanding as of December 31, 2003	$	177
Contracts realized or otherwise settled during the year		(109	)
Other changes in fair values		4
Fair value of contracts outstanding as of September 30, 2004	$	72

12. 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 Energy 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 July 2003, the FERC has been conducting a public audit of compliance with the pre-Order 2004 standards of conduct by Duke Power as an electric transmission provider and its wholesale merchant function and affiliates. Additionally, 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 Energy anticipates that final reports 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 Energy expects the FERC’s recommendations or findings to have no material adverse effect on its consolidated results of operations, cash flows or financial position.

Franchised Electric. Rate Related Information. The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC) approve rates for retail electric sales within their states. The FERC approves Franchised Electric’s rates for electric sales to wholesale customers, except for the other joint owners of the Catawba Nuclear Station whose rates are set through contractual agreements.

On September 9, 2004, the PSCSC approved Duke Power’s proposal for a rate reduction that will lower industrial customers’ electric rates by an average of 2.8 percent for one year beginning October 1, 2004. The rate reduction builds on the company’s efforts to assist the industrial sector in its South Carolina service area by providing financial relief on monthly power bills. Also, the one year rate decrement approved by the PSCSC for all Duke Power retail electric customers in South Carolina effective October 1, 2003, expired on September 30, 2004.

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In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide and nitrogen oxides from the state’s coal-fired power plants over the next ten years. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). Franchised Electric’s amortization expense related to this clean air legislation totals $257 million from inception, with $142 million recorded for the first nine months of 2004 and $87 million recorded for the first nine months of 2003. Expenditures to date total $82 million, with $62 million incurred in the first nine months of 2004 and $9 million incurred in the first nine months of 2003, and are included in net cash from operations on the Consolidated Statements of Cash Flows. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the total estimated cost of $1.5 billion be amortized within the rate freeze period.

Bulk Power Marketing Profit Sharing. On June 9, 2004, the NCUC approved Duke Energy’s proposal to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Power generating units at market based rates (BPM Profits). Duke Energy also informed the NCUC that it would no longer include BPM Profits in calculating its North Carolina retail jurisdictional rate of return for its quarterly reports to the NCUC. As approved by the NCUC, the sharing arrangement provides for 50% of the North Carolina allocation of BPM Profits to be distributed through various public assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum will be used to reduce rates for industrial customers in North Carolina.

On June 29, 2004, Duke Energy informed the PSCSC that it would no longer include BPM Profits in calculating its South Carolina retail jurisdictional rate of return for its quarterly reports to the PSCSC. Duke Energy has since established Advance SC LLC, a South Carolina limited liability company, to receive 50% of the South Carolina retail allocation of the BPM Profits to be distributed through various public assistance programs, and to support certain education programs that promote economic development, and grants to promote the attraction and retention of industrial customers in Duke Power’s South Carolina service area. Advance SC LLC is managed by a board of directors that will act independently of Duke Energy. The board consists of representatives from Duke Power’s service area, including representatives from industrial customers, educational institutions, governmental and economic development agencies, and Duke Energy. The PSCSC has not addressed the proposed change in reporting BPM Profits. Duke Energy’s sharing proposal does not require PSCSC approval.

The sharing agreement in both states applies to BPM Profits from January 1, 2004 until the earlier of December 31, 2007, or the effective date of any rates approved by the respective commission after a general rate case. Profits that have been or that will be shared (Shared Profits) of $31 million have been recorded in 2004 (with a year-to-date amount of $26 million recorded in the second quarter, and $5 million recorded in the third quarter). The Shared Profits were booked as a $17 million decrease to revenues (for the portion related to reduced industrial customers rates) and a $14 million charge to expenses (for the portion related to donations to charitable, educational and economic development programs in North Carolina and South Carolina).

Depreciation and Decommissioning Studies. The operating licenses for Duke Energy’s nuclear units are subject to renewal. In December 2003, Duke Energy was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy was granted renewed operating licenses for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit). The renewed license term of the nuclear units will not impact depreciation or nuclear decommissioning rates unless justified by depreciation and decommissioning studies and funding plans filed with the NCUC and the PSCSC. Preparation of the depreciation study is currently underway and is expected to be completed during 2004.

In June 2004 Duke Power filed with the NCUC and PSCSC the results of a 2003 nuclear decommissioning study, which indicate an estimated cost of $2.32 billion to decommission the facilities. The previous study,

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conducted in 1999, estimated a decommissioning cost of $1.91 billion ($2.15 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning).

In October 2004, Duke Power filed the results of a funding study with the NCUC. The funding study, which was based on the updated decommissioning cost estimate and renewed operating licenses, indicates that an annual funding level of $48 million (compared to a current level of approximately $70 million) is required to fully cover the estimated decommissioning costs. NCUC rules allow stakeholders time to evaluate and comment on the decommissioning and funding studies. The NCUC would then rule on whether any change in Duke Power’s decommissioning expense is necessary. As a result, any potential change in decommissioning expense or the asset retirement obligation cannot be determined at this time.

In the second quarter of 2004, Duke Energy made an approximately $262 million contribution to its external nuclear decommissioning fund. This contribution was shown as an investing activity on the Consolidated Statement of Cash Flows for 2004.

Other Matters. In 2001, the NCUC and the PSCSC began a joint investigation, along with the Public Staff of the NCUC, regarding some Duke Power regulatory accounting entries for 1998, including the classification of nuclear insurance distributions. As part of their investigation, the NCUC and the PSCSC jointly engaged an independent firm to conduct an accounting investigation of Duke Power’s accounting records from 1998 through June 30, 2001. In 2002, Duke Power entered into a settlement agreement with the staffs of the NCUC and the PSCSC in which the parties agreed to accounting changes primarily related to nuclear insurance distributions, a one-time $25 million credit to Duke Power’s deferred fuels account for the benefit of North Carolina and South Carolina customers, the reclassification of $50 million of a $58 million suspense account to a nuclear insurance operation reserve account, and an additional $2 million adjustment to the nuclear insurance operation reserve account. The remaining $8 million in the suspense account was credited to income, resulting in a net $19 million pre-tax charge in 2002. The NCUC and the PSCSC approved the settlement in 2003. A residential retail customer and the Carolina Utility Customers Association Inc. (CUCA), a group that represents certain industrial customers in regulatory proceedings before the NCUC, appealed the NCUC decision to the North Carolina Court of Appeals, which affirmed the NCUC’s decision on February 17, 2004. CUCA further appealed to the Supreme Court of North Carolina and on August 12, 2004, the court denied and dismissed the appeal.

In 2002, the NCUC denied a petition by CUCA to initiate a general rate proceeding and dismissed its complaint alleging unjust and unreasonable rates charged by Duke Power. CUCA appealed this order to the North Carolina Court of Appeals, which ruled on February 17, 2004 that the NCUC’s denial of CUCA’s petition and complaint was proper and affirmed the NCUC’s order. CUCA further appealed to the Supreme Court of North Carolina and on August 12, 2004, that court denied and dismissed the appeal.

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.

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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 Energy’s consolidated results of operations, cash flows or financial position.

13. Commitments and Contingencies

Environmental

Duke Energy 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 Energy 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 Energy operations, sites formerly owned or used by Duke Energy 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 Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy 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. Eight of Duke Energy’s 11 coal and nuclear generating facilities in North and South Carolina and its 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 Energy 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 and the states of North Carolina and South Carolina. In 2000, the court upheld most aspects of the EPA rule. The same court subsequently extended the compliance

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deadline for emission reductions to May 31, 2004. Both North Carolina and South Carolina have revised their SIPs in response to the EPA’s 1998 rule, and the EPA has approved those revisions. Duke Energy has completed the necessary actions to meet the EPA rule and requirements, incurring approximately $653 million of an anticipated $668 million in capital costs for emission controls through September 2004.

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 Energy 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 Energy’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 CO₂ emissions 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 Energy 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 Energy will continue to assess and respond to the potential implications of greenhouse gas policies applicable to Duke Energy’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 $81 million as of September 30, 2004 and $94 million as of December 31, 2003. The accrual for extended environmental-related activities represents Duke Energy’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.

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Litigation

New Source Review (NSR)/EPA Litigation. In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a complaint against Duke Energy in the U.S. District Court in Greensboro, North Carolina, for alleged violations of the NSR provisions of the Clean Air Act (CAA). The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units were major modifications, as defined in the CAA, and that Duke Energy violated the CAA’s NSR requirements when it undertook those projects without obtaining permits and installing emission controls for sulfur dioxide, nitrogen oxide and particulate matter. The complaint asks the Court to order Duke Energy to stop operating the coal-fired units identified in the complaint, install additional emission controls and pay unspecified civil penalties.

Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions. Moreover, the EPA’s allegations run counter to previous EPA guidance regarding the applicability of the NSR permitting requirements. In 2003, the Court issued an opinion in response to the parties’ motions for summary judgment which effectively adopted Duke Energy’s position regarding the legal tests for determining what is “routine” and for calculation of emissions. Based upon a joint motion of the parties in the case, the Court on April 15, 2004 entered an Order and Final Judgment finding in favor of Duke Energy. The joint motion notified the Court that the government could not prove its allegations at trial against Duke Energy in light of the legal standards established by the Court in its 2003 order. The judgment reflects that Duke Energy did not violate the NSR program under the CAA. The government filed its appeal of the judgment to the U.S. Fourth Circuit Court of Appeals in June 2004. Based on the current rulings by the trial court, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position. Subsequent rulings by an appellate court could significantly affect the outcome.

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 Energy affiliates, and current and former Duke Energy 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 Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but, based on rulings by trial courts and the California Settlement, Duke Energy 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.

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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 Energy’s assessment of possible outcomes in this matter, Duke Energy 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 Energy 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 Energy 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 Energy 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 Energy 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 Energy does not believe the outcome of any remaining

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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 Energy 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 Energy		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

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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 Energy 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 Energy 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 Energy 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 Energy is 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

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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 Energy will incur any liability or to estimate the damages, if any, that Duke Energy 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 Energy affiliates engaged in transactions with various Enron entities prior to the bankruptcy filings. In 2001, Duke Energy recorded a reserve to offset its exposure to Enron. In 2002, various Enron trading entities demanded payment from DETM and DEM for some energy commodity sales transactions without regard to any set-off rights. DETM and DEM 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, DEM and other Duke Energy 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 $130 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, $21 million at DEM 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 Energy. 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 Energy or any of its affiliates as a result of these matters.

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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 Energy’s consolidated results of operations, cash flows or financial position.

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power on its electric generation plants during the 1960s and 1970s. In late 1999, after experiencing a significant increase in claims and conducting a comprehensive review, Duke Energy recorded an $800 million accrual to reflect the purchase of a third-party insurance policy and to cover anticipated future claims not recoverable under that policy. The insurance policy, combined with amounts covered by self-insurance reserves, provides for paid claims to an aggregate of $1.6 billion. Duke Energy conducted another review in 2003, and continues to estimate that claims will not exceed such amount. Duke Energy is uncertain as to when claims will be received, and portions may not be received and paid for 30 or more years. While Duke Energy has recorded an accrual related to this estimated liability, such estimates cannot be made with certainty and may change. Factors such as the frequency and magnitude of claims could change the estimates of the injuries and damages liability and insurance recoveries and result in a different amount than is currently reflected in the Consolidated Financial Statements. However, due to Duke Energy’s insurance program relating to this liability, management believes that any changes in the estimates would have no material adverse effect on consolidated results of operations, cash flows or financial position.

Other Litigation and Legal Proceedings. Duke Energy 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.

14. Guarantees and Indemnifications

Duke Energy 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 Energy 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 Energy, 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

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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 Energy 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 Energy 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 Energy 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 Energy 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.

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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 $875 million. Of this amount, approximately $675 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $125 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 $350 million. Of this amount, approximately $300 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities. 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 $85 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 $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 Energy 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 Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Energy related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first

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$2.5 million paid by Duke Energy related to the DukeSolutions guarantees. Further, Duke Energy 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 Energy 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 Energy 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 8. 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 Energy 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 Energy for any payments made under the $120 million letter of credit.

Duke Energy 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 Energy’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 Energy 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.

15. New Accounting Standards

The following new accounting standards have been adopted by Duke Energy 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 Energy 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 Energy to re-evaluate its accounting policy for forward sales contracts. As a result, Duke Energy 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,

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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 mandatorily redeemable stock, 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 Energy’s existing financial instruments beginning July 1, 2003.

Duke Energy’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited-life entities, which are required to be liquidated or dissolved on a certain date, based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests under FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” Duke Energy 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 Energy 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 Energy’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 Energy 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 Energy). 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 Energy), 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 Energy). FIN 46 and FIN 46R may be applied prospectively with a cumulative-effect

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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 Energy 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 Energy 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 Energy’s total assets was not material. Duke Energy adopted the provisions of FIN 46R on December 31, 2003, related to its special-purpose entities consisting of its remaining trust subsidiaries that issued trust preferred securities. Since Duke Energy is not the primary beneficiary of those trust subsidiaries, those entities have been deconsolidated in the accompanying Consolidated Financial Statements. As a result, affiliate debt to the trusts 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 Energy 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 14), Duke Energy 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 Energy’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 Energy 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, electricity capacity 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 Energy’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-06, “Participating Securities and the Two-Class Method under FASB Statement No. 128, ‘Earnings Per Share’.” In March 2004, the EITF reached consensus in EITF Issue No. 03-06, which requires the two-class method for calculating basic earnings per share (EPS) for certain securities that are considered to participate in earnings with common shareholders. EITF Issue No. 03-06 is effective for Duke Energy beginning with the second quarter of 2004, and may require restatement of previously reported EPS measures if any changes to the EPS calculation are required pursuant to the consensus. Duke Energy’s Equity Units are considered participating securities under the consensus; however, such participation is contingent upon future events. As a result, the Equity Units will not impact the calculation of EPS until the occurrence of the future events.

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

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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 Energy’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 Energy adopted FSP FAS 106-2 retroactively to the date of enactment of the Act, December 8, 2003, as allowed by the FSP. See Note 6 for discussion of the effects of adopting this FSP.

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 Energy 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.

EITF Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share.” In September of 2004, the EITF reached a consensus on Issue No. 04-8. The consensus requires that the potential common stock related to contingently convertible securities (Co-Cos) with market price contingencies be included in diluted EPS calculations using the if-converted method specified in SFAS No. 128, “Earnings per Share,” whether the market price contingencies have been met or not. Co-Cos generally require conversion into a company’s common stock if certain specified events occur, such as a specified market price for the company’s common stock. Prior to the issuance of EITF Issue No. 04-08, Co-Cos were treated as contingently issuable shares under SFAS No. 128, and therefore, the contingencies, must have been met in order for the potential common shares to be included in diluted EPS. Therefore, Co-Cos were

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only included in diluted EPS during periods in which the contingencies had been met. The consensus is effective for fiscal years ending after December 15, 2004 and will be required to be applied retroactively to periods in which any Co-Cos were outstanding so that the corresponding diluted EPS calculations will be restated.

As discussed in Note 2 in May of 2003, Duke Energy issued $770 million par value of contingently convertible notes, bearing an interest rate of 1.75% per annum that contain several contingencies, including a market price contingency that, if met, require conversion of the notes into Duke Energy common stock. Conversion is required if any one of the contingencies is met. Therefore, upon adoption of Issue No. 04-08 on December 31, 2004, Duke Energy will be required to include the potential common shares in the calculation of diluted EPS for all periods in which the $770 million contingently convertible notes have been outstanding. Duke Energy continues to evaluate the impact of this pronouncement but currently anticipates that the adoption of EITF Issue No. 04-08 will have an approximate 3% or less negative impact on diluted earnings per share for the periods in which the $770 million contingently convertible notes have been outstanding. See Note 14 to Duke Energy’s 2003 Annual Report on Form 10-K/A for further information on the $770 million contingently convertible notes.

The following new accounting standard has been issued, but has not yet been fully adopted by Duke Energy 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 Energy 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 Energy for the year ending December 31, 2004.

16. Income Tax Expense

The effective income tax rate was 24% for the three months and 25% for the nine months ended September 30, 2004, compared to 129% for the three months and 32% for the nine months ended September 30, 2003. The decreased rates for the current year were due primarily to the reduction of $52 million of state and federal income tax reserves (see discussion below) and $48 million of tax benefit from the change in deferred taxes as a result of a change in state tax rates (see discussion below).

The $52 million reserve reduction occurred in the second quarter of 2004 due to the resolution of various income tax positions taken by Duke Energy and changes in estimates.

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On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owed merchant generation facilities being owned by a newly created entity, Duke Energy Americas, LLC (DEA), a directly wholly owned subsidiary of Duke Capital. DEA and Duke Capital are pass-through entities for U.S. income tax purposes. As a result of these changes, Duke Capital 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.

17. 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 6, in October 2004 Duke Energy 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, which will result in an approximate $45 million 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 Energy consolidated financial statements.

For information on subsequent events related to debt and credit facilities and preferred and preference stock, see Note 5 and for information on subsequent events related to litigation and contingencies, see Note 13. For information on the subsequent sale of the Moapa facility, see Note 9.

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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 Energy’s business strategy is to develop integrated energy businesses in targeted regions where Duke Energy’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 shareholders. For an in-depth discussion of Duke Energy’s business strategy and economic factors, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Energy’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	$	5,507		$	5,549		$	(42	)	$	16,466		$	16,840		$	(374	)
Operating expenses		4,652			5,262			(610	)		14,120			15,000			(880	)
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		(4	)		(79	)		75			(353	)		(76	)		(277	)
Operating income		879			244			635			2,142			1,811			331
Other income and expenses, net		54			103			(49	)		203			472			(269	)
Interest expense		342			375			(33	)		1,035			1,027			8
Minority interest expense (benefit)		61			(11	)		72			142			89			53
Earnings (loss) from continuing operations before income taxes		530			(17	)		547			1,168			1,167			1
Income tax expense (benefit) from continuing operations		129			(22	)		151			296			368			(72	)
Income from continuing operations		401			5			396			872			799			73
(Loss) income from discontinued operations, net of tax		(12	)		44			(56	)		260			61			199
Income before cumulative effect of change in accounting principle		389			49			340			1,132			860			272
Cumulative effect of change in accounting principle, net of tax and minority interest		—			—			—			—			(162	)		162
Net income		389			49			340			1,132			698			434
Dividends and premiums on redemption of preferred and preference stock		2			3			(1	)		7			13			(6	)
Earnings available for common stockholders	$	387		$	46		$	341		$	1,125		$	685		$	440

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

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Overview of Drivers and Variances

Three Months Ended September 30, 2004 as Compared to September 30, 2003. Significant items that contributed to increased earnings available for common stockholders for the quarter included:

• Severance charges in 2003 of $105 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 regulatory action by the Public Service Commission of South Carolina (PSCSC) in 2003 which resulted in decreased earnings of $46 million at Franchised Electric, $16 million of which was due to an order to write-off regulatory assets related to debt issuance costs through interest expense

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

• A $48 million tax benefit in 2004 related to the realignment of certain subsidiaries of Duke Energy and the pass-through structure of these for U.S. income tax purposes (see Note 16 to the Consolidated Financial Statements), and

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

Those increases in earnings available for common stockholders were partially offset by:

• 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.

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 increased earnings available for common stockholders for the nine months included:

• 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 $130 million (net of minority interest of $5 million) pre-tax gain in 2004 related to the settlement of the Enron bankruptcy proceedings (see Note 13 to the Consolidated Financial Statements)

• The reduction of various income tax reserves in 2004 totaling approximately $52 million (see Note 16 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 $162 million, net of tax and minority interest.

Those items were partially offset by:

• An approximate $360 million pre-tax charge in the first quarter of 2004 associated with the sale of DENA’s southeastern plants (see Note 8 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 13 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 Energy’s 60/40 joint venture with ExxonMobil Corporation), and higher plant fuel costs due to overall higher realized natural gas prices in 2004.

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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:

• An $81 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, partially offset by

• A $44 million increase in Regulated Electric revenues, due primarily to a $30 million increase due to a rate decrement ordered by the PSCSC and recorded during the third quarter of 2003, and an increase in collected fuel revenues in 2004, driven by fuel rates for retail customers due primarily to increased coal costs.

Nine Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven by a $637 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

• Decreased revenues at Duke Energy Merchants LLC (DEM), as a result of the decision in 2003 to exit the refined products and NGL business at DEM, 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 were:

• A $166 million increase in Regulated Electric revenues, due primarily to favorable weather, increased fuel rates and increased unbilled fuel revenues at Franchised Electric, and

• 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 $165 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 $138 million decrease in Operation, Maintenance and Other, due primarily to severance costs of $105 million in 2003 and the sale of DENA’s southeast region plants in 2004, and

• A $133 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).

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Nine Months Ended September 30, 2004 as Compared to September 30, 2003. The decrease was driven by a $711 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

• Decreased purchases at DEM, due to the decision in 2003 to exit the refined products and NGL business at DEM, 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.

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Consolidated Operating Income

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 Other driven by operating expense reductions and a gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company, and

• 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 Tranmission’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.

47

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, DEM and Duke Energy’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 Energy, 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 Energy’s ownership interest in operations without regard to financing methods or capital structures.

Duke Energy’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
Franchised Electric	$	453		$	436		$	1,215		$	1,206
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		875			439			2,181			2,410
Other		(25	)		(88	)		(56	)		(205	)
Interest expense		(342	)		(375	)		(1,035	)		(1,027	)
Minority interest expense and other a		22			7			78			(11	)
Consolidated earnings (loss) from continuing operations before income taxes	$	530		$	(17	)	$	1,168		$	1,167

^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.

48

Franchised Electric

	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	$	1,419	$	1,359	$	60		$	3,918	$	3,720	$	198
Operating expenses		967		930		37			2,714		2,552		162
Gains on sales of other assets, net		—		1		(1	)		3		2		1
Operating income		452		430		22			1,207		1,170		37
Other income, net of expenses		1		6		(5	)		8		36		(28	)
EBIT	$	453	$	436	$	17		$	1,215	$	1,206	$	9
Sales, Gigawatt-hours (GWh)		21,904		22,163		(259	)		63,954		63,621		333

The following table shows the changes in billed GWh sales and average number of customers for Franchised Electric.

Increase (decrease) over prior year	Three Months Ended		Nine Months Ended
Residential sales a	0.5	%	6.3	%
General service sales a	1.0	%	4.1	%
Industrial sales a	3.6	%	0.8	%
Wholesale sales	(30.7	)%	(20.5	)%
Total Franchised Electric sales b	(1.2	)%	0.5	%
Average number of customers	1.8	%	1.7	%

^a Major components of Franchised Electric’s retail sales

^b Consists of all components of Franchised Electric’s sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

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

Operating Revenues. The increase was driven primarily by:

• A $30 million increase due to a rate decrement ordered by the PSCSC and recorded during the third quarter of 2003

• A $27 million increase in collected fuel revenues, driven by increased fuel rates for retail customers due primarily to increased coal costs

• A $15 million increase in unbilled fuel revenues, due to increased fuel expense, primarily resulting from increased coal costs, not yet collected in rates

• A $10 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory

• A $12 million decrease in wholesale power revenues, due primarily to lower sales volumes resulting from lower availability of coal

• A $3 million decrease due to sharing of profits from wholesale power sales with customers in North Carolina in 2004 (see Note 12 to the Consolidated Financial Statements).

49

Operating Expenses. The increase was driven primarily by:

• Increased operating and maintenance expenses of $37 million, excluding storm costs, due primarily to increased governance costs in 2004 and a reduction of incentive costs recorded in 2003

• Increased fuel expenses of $30 million, due primarily to increased spot and contractual coal costs

• Increased storm costs of $10 million, due primarily to Hurricane Ivan in September 2004

• Increased depreciation expense of $6 million, due to additional capital spending

• Decreased severance expenses of $46 million, due to workforce reductions in 2003.

EBIT. The increase in EBIT resulted primarily from severance charges and the rate decrement ordered by the PSCSC during the third quarter of 2003, coupled with continued growth in the number of residential and general service customers in 2004. These changes were partially offset by increased operating and maintenance expenses, lower sales to wholesale customers and charges related to Hurricane Ivan in 2004.

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

Operating Revenues. The increase was driven primarily by:

• A $74 million increase in collected fuel revenues driven by increased fuel rates for retail customers, due primarily to increased coal costs and increased sales resulting from favorable weather

• A $70 million increase in GWh sales to retail customers, due to favorable weather during the period

• A $64 million increase in unbilled fuel revenues, due to increased fuel expense, primarily resulting from increased coal costs, not yet collected in rates

• A $30 million increase due to a rate decrement ordered by the PSCSC and recorded during the third quarter of 2003

• A $26 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory

• A $43 million decrease in wholesale power revenues, due primarily to lower sales volumes resulting from lower generation availability and lower availability of coal

• A $17 million decrease in sales to industrial customers, due primarily to the continuing decline in sales to textile customers in North Carolina and South Carolina

• A $17 million decrease due to sharing of profits from wholesale power sales with customers in North Carolina in 2004 (see Note 12 to the Consolidated Financial Statements).

Operating Expenses. The increase was driven primarily by:

• Increased fuel expenses of $127 million, due primarily to increased spot and contractual coal costs and increased sales to retail customers

• Increased operating and maintenance expenses of $25 million, excluding outage and storm costs, primarily due to increased governance costs in 2004

• Increased nuclear and fossil outage costs of $18 million, driven by increased outage days during 2004

• Increased depreciation expense of $18 million due to additional capital spending

• Increased donations of $14 million, due to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina (see Note 12 to the Consolidated Financial Statements)

• Decreased severance expenses of $46 million due to workforce reductions in 2003

• Decreased storm costs of $8 million, due primarily to costs from major storms in February and September 2003 partially offset by costs of major storms in January, March and September of 2004.

50

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

• A $16 million decrease in the allowance for funds used during construction, due primarily to large maintenance capital projects that were completed in 2003

• An $11 million decrease in the return on deferred costs related to the purchase of capacity from the joint owners of the Catawba Nuclear Station.

EBIT. The increase in EBIT resulted primarily from increased sales to retail customers due to favorable weather in 2004, severance charges in 2003, the rate decrement ordered by the PSCSC during 2003, and continued growth in the number of residential and general service customers in 2004. These changes were partially offset by lower sales to wholesale customers, increased operating and maintenance expenses (including increased expenses related to fossil and nuclear outages), sharing of profits from wholesale power sales, increased depreciation expense and lower sales to industrial customers.

Matters Impacting Future Franchised Electric’s Results

Reliable deliveries of coal continue to be a challenge for electric utilities in the Southeast United States. To the extent coal inventories are below needed levels, Franchised Electric’s wholesale opportunities will be limited during the remainder of 2004.

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.

51

Operating Expenses. The decrease was driven primarily by:

• An $18 million decrease due to severance costs in the prior year quarter, offset by advalorem 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.

52

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.

53

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 Energy’s joint venture with ConocoPhillips. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level 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 were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

54

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 Energy 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.

55

Duke Energy North America

	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 a		7,213			9,130			(1,917	)		17,596			18,750			(1,154	)
Proportional megawatt capacity in operation											9,890			15,836			(5,946	)

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

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.

56

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 13 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 13 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 8 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.

57

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.

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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.

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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.

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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 $63 million for the three months ended September 30, 2004, compared to the same period in 2003, due primarily to charges of $33 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.

EBIT for Other increased $149 million for the nine months ended September 30, 2004, compared to the same period in 2003. The increase was due primarily to an $83 million increase in DEM’s EBIT due to a $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad), a $38 million reduction in operating expenses as a result of a $21 million gain related to the settlement of the Enron bankruptcy proceedings in April 2004, and $17 million decrease in general and administrative expense due to lower activity as a result of the decision in 2003 to exit DEM’s refined products and NGL business. In addition, the absence of 2003 losses of $32 million from adverse market movements against some commodity positions positively affected the overall year over year increase. Also contributing to the increase was lower governance costs in 2004 due to cost reductions and cost shifts from corporate to the operating units.

Additionally, 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 Energy has a wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), that provides insurance coverage to Duke Energy 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 Earnings Available for Common Stockholders

For the three months ended September 30, 2004, the decrease in interest expense was due primarily to:

• A $40 million decrease from net debt reduction and refinancing activities, and

• A $16 million write-off in 2003 due to an order by the PSCSC to write off regulatory assets related to debt issuance costs through interest expense, partially offset by

• $8 million of lower capitalized interest, due to decreased construction activity

• $8 million for higher interest costs in Brazil, due to Duke Energy’s Brazilian debt being indexed annually to Brazilian inflation, and

• A $4 million increase associated with Canadian exchange rates.

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For the nine months ended September 30, 2004, the increase in interest expense was due primarily to:

• $33 million of lower capitalized interest, due to decreased construction activity

• $26 million of expenses related to financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with Statement of Financial Accounting Standards (SFAS) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.”

• $17 million higher interest costs in Brazil, due to Duke Energy’s Brazilian debt being indexed annually to inflation, and

• A $15 million increase associated with Canadian exchange rates, partially offset by

• A $72 million decrease from net debt reduction and refinancing activities, and

• A $16 million write-off in 2003 due to an order by the PSCSC to write off regulatory assets related to debt issuance costs through interest expense.

Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Energy and its subsidiaries. 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 $55 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 Energy’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 $108 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 rate was 24% for the three months and 25% for the nine months ended September 30, 2004, compared to 129% for the three months and 32% for the nine months ended September 30, 2003. The decreased rates for the current year were due primarily to the reduction of $52 million of state and federal income tax reserves during the second quarter of 2004 and $48 million of tax benefit from the change in deferred taxes as a result of a change in state tax rates during the third quarter of 2004. (See Note 16 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 Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $151 million, or $0.17 per basic share, 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 $11 million, or $0.01 per basic share, related to the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

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LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities increased $933 million for the nine months ended September 30, 2004, compared to the same period in 2003, due primarily to changes in working capital, which included the receipt of a $505 million tax refund, decreases in inventory at DENA and DEM, higher cash settlements from trading and marketing activities, and a contribution to the U.S. pension plan of $181 million occurring in the 2003 period.

Investing Cash Flows

Net cash used in investing activities decreased $219 million for the nine months ended September 30, 2004, compared to the same period in 2003. Of this decrease, $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 $195 million relates to decreased capital expenditures at DENA and Natural Gas Transmission partially offset by increased capital expenditures at Franchised Electric. These decreases in cash used were partially offset by a $309 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 Energy’s sale of the TEPPCO class B units; DEM’s sale of DE Hydrocarbons; 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.

For 2004, Duke Energy expects annual capital and investment expenditures to be approximately $2.5 billion, including approximately $400 million for Crescent to be included in operating cash flows, as disclosed in “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Liquidity and Capital Resources – Known Trends and Uncertainties” in Duke Energy’s Annual Report on form 10-K/A for December 31, 2003.

Financing Cash Flows and Liquidity

The fixed charges coverage ratio, calculated using Securities and Exchange Commission (SEC) guidelines, was 2.2 times for the nine months ended September 30, 2004 and 2.0 times for the nine months ended September 30, 2003.

Net cash used in financing activities increased $369 million for the nine months ended September 30, 2004, compared to the same period in 2003. This change was due primarily to approximately $1.0 billion of higher redemptions and net paydowns of long-term debt, commercial paper and notes payable during 2004, offset by approximately $730 million of higher proceeds from common stock issuances during 2004, driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May 2004. Total debt reductions of approximately $2.4 billion in 2004 consisted of $1.6 billion in net cash redemptions (see Note 5 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 Energy’s cash requirements for 2004 are expected to be funded by cash from operations, the sale of non-strategic assets, and the settlement of the forward stock purchase component of outstanding Equity Units in November 2004, and are expected to be adequate for funding capital expenditures, dividend payments and planned debt reductions.

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Significant Financing Activities. For discussion of Duke Energy’s significant financing activities, see Note 5 to the Consolidated Financial Statements.

Available Credit Facilities and Restrictive Debt Covenants. Duke Energy’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 Energy 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 Energy, Duke Capital LLC (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 Energy’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 Energy 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 Energy a	BBB	Baa1	Not applicable
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 Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors, Duke Energy is unable to execute its business plan, or if its earnings outlook materially deteriorates, Duke Energy’s ratings could be further affected.

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Duke Energy 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 Energy’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 Energy’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 Energy’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 Energy and its subsidiaries had effective SEC shelf registrations for up to $2,042 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 Energy 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.

Duke Energy’s InvestorDirect Choice Plan allows investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. Duke Energy also sponsors employee savings plans that cover substantially all employees. To better manage cash flows, financing activities and reduce the growth in the number of shares outstanding, Duke Energy began satisfying its share requirements for these plans through the purchase of shares in the open market during the second quarter of 2004. Additionally, Duke Energy will continue to issue authorized but previously unissued shares of its common stock to meet its other employee benefit requirements.

Contractual Obligations and Commercial Commitments

Duke Energy enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. For an in-depth discussion of Duke Energy’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 Energy’s Annual Report on Form 10-K/A for December 31, 2003.

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CURRENT ISSUES

For information on current issues related to Duke Energy, see the following Notes to the Consolidated Financial Statements: Note 12, Regulatory Matters, and Note 13, Commitments and Contingencies.

New Accounting Standards

The following new accounting standard has been issued, but has not yet been fully adopted by Duke Energy 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

• 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 Energy 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 Energy for the year ending December 31, 2004.

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 6 to the Consolidated Financial Statements, in October 2004 Duke Energy 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, which will result in an approximate $45 million 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 Energy consolidated financial statements.

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For information on subsequent events related to debt and credit facilities and preferred and preference stock, see Note 5 to the Consolidated Financial Statements. For information on subsequent events related to litigation and contingencies, see Note 13 to the Consolidated Financial Statements. For information on the subsequent sale of the Moapa facility see Note 9 to the Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of Duke Energy’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Energy’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 Energy 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 Energy’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 3rd Quarter 2004 a		Estimated Average One- Day Impact on Operating Income for the Year 2003 a		High One-Day Impact on Operating Income for 3rd Quarter 2004 a		Low One-Day Impact on Operating Income for 3rd Quarter 2004 a
Calculated DER	$	8	$	7	$	8	$	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.}

Equity Price Risk

As mentioned in the “Investing Cash Flows” section of “Liquidity and Capital Resources”, Duke Energy contributed cash of $262 million in the second quarter of 2004 to a trust fund for nuclear decommissioning costs. The entire trust invests funds primarily in equity securities, fixed-rate and fixed-income securities, and cash and cash equivalents. Therefore, the contribution will be exposed to price fluctuations in equity markets and changes in interest rates.

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Item 4. Controls and Procedures.

Duke Energy’s management, including the Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Duke Energy’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 Energy’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in Duke Energy’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 Energy’s 2003 Annual Report on Form 10-K/A, Duke Energy’s independent registered public accounting firm, Deloitte & Touche LLP (Deloitte), noted certain matters involving Duke Energy’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 Energy’s financial statements. Because of this identified reportable condition and Duke Energy’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 Energy’s internal control procedures.

Management has concluded that the Disclosure Controls Evaluation identified no changes in Duke Energy’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 Energy’s internal control over financial reporting.

As disclosed in the Notes to the Consolidated Financial Statements in Duke Energy’s 2003 Annual Report on Form 10-K/A and June 30, 2004 Quarterly Report on Form 10-Q/A, in 2004 Duke Energy 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.

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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 13 to the Consolidated Financial Statements, “Commitments and Contingencies;” and Item 3, “Legal Proceedings,” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” in Duke Energy’s Annual Report on Form 10-K/A for December 31, 2003, which are incorporated herein by reference.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

Issuer Purchases of Equity Securities for Third Quarter of 2004

Period	Total Number of Shares (or Units) Purchased a	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs b	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under Plans or Programs b
July 1 to July 31	195,899	$	21.00	—	—
August 1 to August 31	193,059	$	22.03	—	—
September 1 to September 30	186,792	$	22.55	—	—

^a Shares purchased to satisfy company matching obligations for accounts of participants in the Duke Energy Retirement Savings Plan.

^b As of September 30, 2004, Duke Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of the security holders of Duke Energy during the third quarter of 2004.

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Item 6. Exhibits

(a) Exhibits

Exhibit Number
10.1	Third Amendment to Parent Company Agreement among Duke Energy Field Services Corporation, Duke Energy Field Services, LLC, Conoco Phillips Company and Duke Energy Corporation dated as of July 29, 2004.
10.2	First Amendment to Key Employee Severance Agreement and General Release between Duke Energy Corporation and Richard J. Osborne, dated August 21, 2004.
10.3	First Amendment to Change in Control Agreement and General Release between Duke Energy Corporation and Richard J. Osborne, dated August 18, 2004.
10.4	Second Amendment to Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC dated as of July 29, 2004.
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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	DUKE ENERGY CORPORATION
Date: November 9, 2004	/s/ David L. Hauser
	David L. Hauser Group Vice President and Chief Financial Officer

Date: November 9, 2004	/s/ Keith G. Butler
	Keith G. Butler Vice President and Controller

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