Duke Energy Carolinas 10-Q 2004 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended March 31, 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.

Yesx No¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yesx 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 at April 30, 2004............914,883,510

DUKE ENERGY CORPORATION

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2004

INDEX

Item		Page
PART I. FINANCIAL INFORMATION
1.	Financial Statements	1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003	1
	Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003	2
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003	4
	Notes to Consolidated Financial Statements	5
2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	30
3.	Quantitative and Qualitative Disclosures About Market Risk	45
4.	Controls and Procedures	46
PART II. OTHER INFORMATION
1.	Legal Proceedings	47
6.	Exhibits and Reports on Form 8-K	47
	Signatures	49

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

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

i

• 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 further 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, processing and other infrastructure projects

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

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

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

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

ii

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 March 31,
	2004			2003
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids, and other	$	3,612		$	4,014
Regulated electric		1,251			1,279
Regulated natural gas		982			879
Total operating revenues		5,845			6,172
Operating Expenses
Natural gas and petroleum products purchased		3,032			3,492
Operation, maintenance and other		888			674
Fuel used in electric generation and purchased power		564			548
Depreciation and amortization		436			431
Property and other taxes		154			140
Total operating expenses		5,074			5,285
(Losses) Gains on Sales of Other Assets, net		(338	)		2
Operating Income		433			889
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		34			34
Gains on sales of equity investments		—			14
Other income and expenses, net		25			26
Total other income and expenses		59			74
Interest Expense		356			326
Minority Interest Expense		38			50
Earnings From Continuing Operations Before Income Taxes		98			587
Income Tax Expense from Continuing Operations		33			195
Income From Continuing Operations		65			392
Discontinued Operations
Net operating income, net of tax		7			3
Net gain (loss) on dispositions, net of tax		239			(8	)
Income (Loss) From Discontinued Operations		246			(5	)
Income Before Cumulative Effect of Change in Accounting Principle		311			387
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			(162	)
Net Income		311			225
Dividends and Premiums on Redemption of Preferred and Preference Stock		2			3
Earnings Available For Common Stockholders	$	309		$	222
Common Stock Data
Weighted-average shares outstanding
Basic		912			897
Diluted		915			897
Earnings per share (from continuing operations)
Basic	$	0.07		$	0.43
Diluted	$	0.07		$	0.43
Earnings per share (from discontinued operations)
Basic	$	0.27		$	—
Diluted	$	0.27		$	—
Earnings per share (before cumulative effect of change in accounting principle)
Basic	$	0.34		$	0.43
Diluted	$	0.34		$	0.43
Earnings per share
Basic	$	0.34		$	0.25
Diluted	$	0.34		$	0.25
Dividends per share	$	0.275		$	0.275

See Notes to Consolidated Financial Statements

1

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	March 31, 2004		December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	1,500	$	1,160
Receivables, net		2,689		2,888
Inventory		878		1,156
Assets held for sale		297		424
Unrealized gains on mark-to-market and hedging transactions		1,320		1,566
Other		1,056		694
Total current assets		7,740		7,888
Investments and Other Assets
Investments in unconsolidated affiliates		1,365		1,398
Nuclear decommissioning trust funds		960		925
Goodwill		3,932		3,962
Notes receivable		232		260
Unrealized gains on mark-to-market and hedging transactions		1,635		1,857
Assets held for sale		2,089		1,444
Other		887		1,117
Total investments and other assets		11,100		10,963
Property, Plant and Equipment
Cost		46,719		47,157
Less accumulated depreciation and amortization		12,641		12,171
Net property, plant and equipment		34,078		34,986
Regulatory Assets and Deferred Debits
Deferred debt expense		326		275
Regulatory assets related to income taxes		1,194		1,152
Other		913		939
Total regulatory assets and deferred debits		2,433		2,366
Total Assets	$	55,351	$	56,203

See Notes to Consolidated Financial Statements

2

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	March 31, 2004		December 31, 2003
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	2,000	$	2,317
Notes payable and commercial paper		275		130
Taxes accrued		291		14
Interest accrued		305		304
Liabilities associated with assets held for sale		883		651
Current maturities of long-term debt		1,489		1,200
Unrealized losses on mark-to-market and hedging transactions		993		1,283
Other		1,397		1,799
Total current liabilities		7,633		7,698
Long-term Debt, including debt to affiliates of $516 at March 31, 2004 and $876 at December 31, 2003		20,034		20,622
Deferred Credits and Other Liabilities
Deferred income taxes		4,280		4,120
Investment tax credit		162		165
Unrealized losses on mark-to-market and hedging transactions		1,556		1,754
Liabilities associated with assets held for sale		305		737
Other		5,546		5,524
Total deferred credits and other liabilities		11,849		12,300
Commitments and Contingencies
Minority Interests		1,723		1,701
Preferred and preference stock without sinking fund requirements		134		134
Common Stockholders’ Equity
Common stock, no par, 2 billion shares authorized; 914 million and 911 million shares outstanding at March 31, 2004 and December 31, 2003, respectively		9,598		9,519
Retained earnings		4,121		4,060
Accumulated other comprehensive income		259		169
Total common stockholders’ equity		13,978		13,748
Total Liabilities and Common Stockholders’ Equity	$	55,351	$	56,203

See Notes to Consolidated Financial Statements

3

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Three Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	311		$	225
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		476			484
Cumulative effect of change in accounting principle		—			162
Net losses (gains) on sales of equity investments and other assets		80			(4	)
Deferred income taxes		15			(38	)
Purchased capacity levelization		50			47
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		221			(116	)
Receivables		305			(818	)
Inventory		272			166
Other current assets		(314	)		(183	)
Increase (decrease) in
Accounts payable		(400	)		1,063
Taxes accrued		280			309
Other current liabilities		(199	)		114
Other, assets		140			(33	)
Other, liabilities		69			126
Net cash provided by operating activities		1,306			1,504
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net of refund		(620	)		(805	)
Net proceeds from the sales of equity investment and other assets, and sales of and collections on notes receivable		166			306
Other		(5	)		24
Net cash used in investing activities		(459	)		(475	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the Issuance of long-term debt		72			824
Issuance of common stock and common stock related to employee benefit plans		59			80
Payments for the redemption of Long-term debt		(418	)		(882	)
Notes payable and commercial paper		130			(307	)
Distributions to minority interests		(418	)		(837	)
Contributions from minority interests		363			593
Dividends paid		(265	)		(258	)
Other		1			10
Net cash used in financing activities		(476	)		(777	)
Changes in cash and cash equivalents associated with assets held for sale		(31	)		—
Net increase in cash and cash equivalents		340			252
Cash and cash equivalents at beginning of period		1,160			857
Cash and cash equivalents at end of period	$	1,500		$	1,109

See Notes to Consolidated Financial Statements

4

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 an affiliated real estate operation. The Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries, and those variable interest entities where Duke Energy is the primary beneficiary. The Consolidated Financial Statements also reflect Duke Energy’s undivided interest in the Catawba Nuclear Station, which was approximately 12.5% for all periods presented.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. 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 and other factors. These Consolidated Financial Statements and other information included in this quarterly report on Form 10-Q should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in Duke Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003.

Use of Estimates. Conformity with generally accepted accounting principles (GAAP) in the U.S. requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

Reclassifications.Certain prior period amounts have been reclassified to conform to the current period presentation.

2. Earnings Per Common Share

Basic earnings per share are based on a weighted average of common shares outstanding. Diluted earnings per share reflect the potential dilution that could occur if securities or other agreements to issue common stock, 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 numerator for the calculation of both basic and diluted earnings per share is earnings available for common stockholders. The following table reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding.

Weighted-Average Shares Outstanding (in millions)

	Three Months Ended March 31,
	2004	2003
Weighted-average shares outstanding	912	897
Assumed exercise of dilutive securities or other agreements to issue common stock	3	—
Diluted weighted-average shares outstanding	915	897

Options, performance awards and phantom stock awards to purchase approximately 25 million shares as of March 31, 2004 and 30 million as of March 31, 2003 were not included in the computation of diluted earnings per share because either the option exercise prices were greater than the average market price of the common shares during those periods, or the conditions necessary for the achievement of certain performance measures related to the awards had not yet been satisfied.

5

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 Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board (FASB) Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” The following table 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 Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards and reflects the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment to FASB Statement No. 123).”

	Three Months Ended March 31,
Pro Forma Stock Based Compensation (in millions, except per shae amounts)	2004			2003
Earnings available for common stockholders, as reported	$	309		$	222
Add: stock-based compensation expense included in reported net income, net of related tax effects		3			2
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(6	)		(7	)
Pro forma earnings available for common stockholders, net of related tax effects	$	306		$	217
Earnings per share
Basic – as reported	$	0.34		$	0.25
Basic – pro forma	$	0.34		$	0.24
Diluted – as reported	$	0.34		$	0.25
Diluted – pro forma	$	0.34		$	0.24

4. Inventory

Inventory consists primarily of materials and supplies; developed lots; natural gas and natural gas liquid products held in storage for transmission, processing and sales commitments; coal held for electric generation; and petroleum products. This inventory is recorded at the lower of cost or market value, primarily using the average cost method.

Inventory (in millions)

	March 31, 2004		December 31, 2003
Materials and supplies	$	434	$	445
Developed lots		215		215
Natural gas		85		299
Coal		77		87
Petroleum products		67		110
Total inventory	$	878	$	1,156

6

5. Debt and Credit Facilities

In February 2004, Duke Energy remarketed $875 million of senior notes, due 2006, underlying its Equity Units and reset the interest rate from 5.87% to 4.302%. As this remarketing followed the remarketing contemplated in the original Equity Units issuance, the remarketing transaction had no immediate accounting implications. Subsequent to this remarketing, Duke Energy entered into an exchange transaction with the purchasers of $475 million of remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009 and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with Emerging Issue Task Force (EITF) Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued at 4.302% was considered extinguished. This exchange transaction resulted in a loss of approximately $11 million which is included in interest expense in the Consolidated Financial Statements.

In March 2004, Duke Energy redeemed the entire issue of 7.20% Duke Energy debt to an affiliate due in 2037. The total redemption price was approximately $350 million. 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 April 2004, Duke Energy retired approximately $1.1 billion of debt, including substantially all of the $900 million of debt associated with the Australian operations that have been classified as discontinued operations as of December 31, 2003. The debt associated with the Australian operations had been reclassified to Current and Non-Current Liabilities Associated with Assets Held for Sale at December 31, 2003 and March 31, 2004. 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.

Additionally, in April 2004, Duke Energy announced that on May 28, 2004, it will redeem Duke Energy Series C 6.60% Senior Notes due 2038, with a face value of $200 million. As the securities are being redeemed at par, security holders will receive $25 per each note held, plus accrued interest to the redemption date.

Available Credit Facilities and Restrictive Debt Covenants. During the three-month period ended March 31, 2004, Duke Energy Field Services, LLC (DEFS) and Duke Australia Finance Pty Ltd. (a wholly owned subsidiary of Duke Energy) replaced portions of their expiring credit facilities, thereby reducing the total amount of credit facilities available by approximately $100 million, as compared to credit facilities available as of December 31, 2003. The credit facilities that have replaced the expired credit facilities are included in the following table which summarizes Duke Energy’s credit facilities and related amounts outstanding as of March 31, 2004. The majority of the credit facilities support commercial paper programs. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in acceleration of due dates of certain borrowings and/or termination of the agreements. As of March 31, 2004, Duke Energy was in compliance with those covenants. In addition, certain of the credit agreements contain cross-acceleration provisions that may allow for acceleration of payments or termination of the agreements upon: (1) nonpayment or (2) acceleration of other significant indebtedness of the applicable borrower or certain of its subsidiaries. None of the credit agreements contain material adverse change clauses.

7

Credit Facilities Summary as of March 31, 2004(in millions)

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
				Commercial Paper		Letters of Credit		Other Borrowings		Total
Duke Energy
$125 364-day bi-laterala, b	August 2004
$475 multi-year syndicateda, b	August 2004
$150 one-year bi-laterala, b	September 2005
Total Duke Energy		$	750	$	371	$	—	$	—	$	371
Duke Capital LLC
$252 364-day syndicated letter of credita, b, c, d	April 2004
$538 multi-year syndicated letter of creditb, c, d	April 2004
$550 multi-year syndicateda, b, c	August 2004
Total Duke Capital LLC			1,340		—		666		—		666
Westcoast Energy Inc.
$153 364-day syndicatedb, e, f	July 2004
$77 two-year syndicatedb, g	July 2005
Total Westcoast Energy Inc.			230		—		—		—		—
Union Gas Limited
$260 364-day syndicatede, h	July 2004		260		—		—		—		—
Duke Energy Field Services, LLC
$250 364-day syndicatedc, e, i	March 2005		250		—		—		—		—
Duke Australia Finance Pty Ltd.
$229 364-day syndicatedc, j, k,	September 2004		229		34		—		109		143
Duke Australia Pipeline Finance Pty Ltd.
$238 multi-year syndicatedk, l,	February 2005		238		—		—		214		214
Totalm		$	3,297	$	405	$	666	$	323	$	1,394

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

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

^c Credit facility contains an interest coverage covenant.

^d On April 9, 2004 credit facility expiration date extended from April 2004 to July 2004.

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

^f Credit facility is denominated in Canadian dollars and was 200 million Canadian dollars as of March 31, 2004.

^g Credit facility is denominated in Canadian dollars and was 100 million Canadian dollars as of March 31, 2004.

^h Credit facility contains covenant requiring debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars, and was 340 million Canadian dollars as of March 31, 2004.

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

^j Credit facility is guaranteed by Duke Capital LLC (Duke Capital), a wholly owned subsidiary of Duke Energy, and is denominated in Australian dollars. During March 2004 credit facility was reduced from 316 million to 300 million Australian dollars and the expiration date was extended to September 2004. Credit facility was 300 million Australian dollars as of March 31, 2004.

^k Credit facility pertains to operations that were classified as discontinued operations at March 31, 2004. Therefore, the outstanding debt associated with the credit facility was reclassified to Current and Non-Current Liabilities Associated with Assets Held for Sale on the Consolidated Balance Sheet. These facilities were retired as a result of the completion of the sale of the Asia-Pacific assets to Alinta, Ltd. In April 2004.

^l Credit facility is guaranteed by Duke Capital, is denominated in Australian dollars, and was 312 million Australian dollars as of March 31, 2004. Duke Australia Pipeline Finance Pty Ltd. is a wholly owned subsidiary of Duke Energy.

^m 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.

8

6. Employee Benefit Obligations

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

Components of Net Periodic Pension Costs(in millions) – for the three month period ended March 31,

	Duke Energy U.S.						Westcoast
	2004			2003			2004			2003
Service cost	$	16		$	18		$	2		$	2
Interest cost on projected benefit obligation		40			44			6			5
Expected return on plan assets		(58	)		(59	)		(6	)		(6	)
Amortization of prior service cost		(1	)		(1	)		—			—
Amortization of net transition asset		(1	)		(1	)		—			—
Amortization of loss		4			—			1			—
Curtailment gain		(1	)		—			—			—
Net periodic pension (income) costs	$	(1	)	$	1		$	3		$	1

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to U.S. plan participants. No decision on 2004 contributions to the U.S. plans has been reached due to timing of U.S. Congressional action over required interest rates used to determine minimum funding requirements.

Westcoast’s policy is to fund the defined benefit retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the defined contribution retirement plans are determined in accordance with the terms of the plan. Duke Energy has contributed $3 million to the Westcoast plans as of March 31, 2004, and anticipates that it will make total contributions of approximately $27 million in 2004.

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

Components of Net Periodic Post-Retirement Benefit Costs (in millions) – for the three month period ended March 31,

	Duke Energy U.S.						Westcoast
	2004			2003			2004		2003
Service cost benefit	$	1		$	1		$	1	$	—
Interest cost on accumulated post- retirement benefit obligation		14			13			1		1
Expected return on plan assets		(5	)		(5	)		—		—
Amortization of net transition liability		4			5			—		—
Curtailment loss		—			5			—		—
Amortization of loss		4			1			—		—
Net periodic post-retirement benefit costs	$	18		$	20		$	2	$	1

9

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 March 31,
	2004			2003
Net Income	$	311		$	225
Other comprehensive income
Foreign currency translation adjustments		(43	)		164
Net unrealized gains on cash flow hedges(a)		127			176
Reclassification into earnings from cash flow hedges(b)		6			(52	)
Other Comprehensive Income		90			288
Total Comprehensive Income	$	401		$	513

^(a) Net unrealized gains on cash flow hedges, net of $52 million tax expense in 2004 and $82 million tax expense in 2003.

^(b) Reclassification into earnings from cash flow hedges, net of $3 million tax expense in 2004 and $26 million tax benefit in 2003.

Accumulated Other Comprehensive Income.The following table shows the 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 tax expense of $55)		(43	)		133		—			90
Balance as of March 31, 2004	$	272		$	431	$	(444	)	$	259

8. Assets Held for Sale and Discontinued Operations

In 2003, Duke Energy decided to exit the merchant power generation business in the Southeastern U.S. In the first quarter of 2004, as a result of the marketing efforts related to Duke Energy North America’s (DENA) eight plants in the region, Duke Energy classified the assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million, which represents the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. The fair value of the plants was based upon the final sales price of $475 million, which Duke Energy announced it had agreed to with KGen Partners LLC on May 4, 2004. The sales price consists of $425 million cash and a $50 million note receivable with principal and interest due no later than 7.5 years after the sale. The agreement includes the sale of all of Duke Energy’s merchant generation assets in the Southeastern U.S. The results of operations related to these assets are not reported within Discontinued Operations due to Duke Energy’s significant continuing involvement in the future operations of the plants including a long-term operating agreement for one of the plants and retention of certain guarantees related to these assets.

10

Also, in the first quarter of 2004, as a result of changes in fair value of International Energy’s Asia Pacific power generation and natural gas transmission businesses, which were classified as held for sale at December 31, 2003, Duke Energy recorded an after-tax gain of $238 million related to the increase in estimated fair value less costs to sell. The gain is a restoration of the loss that was recorded during the fourth quarter of 2003 and is included in Net Gain (Loss) on Dispositions, net of tax, within Discontinued Operations, in the Consolidated Statements of Operations. Fair value was based upon third-party bids received by International Energy in the first quarter of 2004 from its efforts to divest the assets associated with the businesses. On April 23, 2004, Duke Energy announced it had completed the sale of these businesses to Alinta, Ltd. for approximately $1.2 billion, which will result in an additional after-tax gain of approximately $30 million in the second quarter of 2004 in conjunction with the close of the transaction.

The following table presents the carrying values as of March 31, 2004 and December 31, 2003 of the major classes of Assets Held for Sale and associated liabilities in the Consolidated Balance Sheets. In addition to DENA’s eight plants in the Southeastern U.S., which are classified as held for sale at March 31, 2004, the following table includes assets and associated liabilities that were classified as held for sale at both December 31, 2003 and March 31, 2004, including International Energy’s Asia Pacific power generation and natural gas transmission businesses and its European operations, certain turbines and related equipment owned by DENA, and the merchant finance business conducted by Duke Capital Partners, LLC (DCP).

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

	March 31, 2004		December 31, 2003
Current assets	$	297	$	424
Investments and other assets		459		379
Property, plant and equipment, net		1,630		1,065
Total assets held for sale	$	2,386	$	1,868
Current liabilities	$	883	$	651
Long-term debt		125		514
Deferred credits and other liabilities		180		223
Total liabilities associated with assets held for sale	$	1,188	$	1,388

The following table summarizes the operating results that have been classified as Discontinued Operations in the Consolidated Statements of Operations. The three-month period ended March 31, 2004 includes the results for International Energy’s Asia Pacific power generation and natural gas transmission businesses and its European operations, the merchant finance business conducted by DCP, and certain other assets at Field Services. In addition to the above, the three-month period ended March 31, 2003 contains Duke Energy Hydrocarbons LLC and certain of Crescent Resources LLC’s (Crescent) real estate projects that were all disposed of in 2003. For additional information related to the exit of these activities see the Notes to the Consolidated Financial Statements filed as part of Duke Energy’s Form 10-K for the year ended December 31, 2003. None of DENA’s assets held for sale met the criteria for discontinued operations presentation at March 31, 2004, due primarily to Duke Energy’s anticipated continuing involvement in the operations of one or more of the Southeastern plants after the date of sale.

11

Discontinued Operations (in millions)

	Operating Revenues		Operating Income									Net Gain (Loss) on Dispositions
			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 March 31, 2004
International Energy	$	63	$	3		$	(1	)	$	4		$	256		$	18		$	238
Field Services		14		1			—			1			2			1			1
Other		1		2			—			2			—			—			—
Total consolidated	$	78	$	6		$	(1	)	$	7		$	258		$	19		$	239
Three Months Ended March 31, 2003
International Energy	$	201	$	(2	)	$	(1	)	$	(1	)	$	—		$	—		$	—
Field Services		139		3			1			2			—			—			—
Crescent and Other		10		3			1			2			(12	)		(4	)		(8	)
Total consolidated	$	350	$	4		$	1		$	3		$	(12	)	$	(4	)	$	(8	)

9. 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 Duke Energy business units are considered reportable segments under SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information.”.

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

Beginning in 2004, Crescent, formerly part of Other Operations, as defined in Duke Energy’s Annual Report on Form 10-K, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages land holdings primarily in the Southeastern and Southwestern U.S. All other entities previously part of Other Operations and now within Other still remain, primarily: DukeNet Communications, LLC, Duke Energy Merchants, LLC and Duke/Fluor Daniel. Unallocated corporate costs are also recorded in Other in the table below.

Consolidated EBIT is viewed as a non-GAAP measure under the rules of the Securities and Exchange Commission (SEC). Duke Energy includes consolidated EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance for continuing operations. On a segment basis, EBIT excludes discontinued operations and 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. Since the business units do not manage those items, 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.

12

On a consolidated basis, EBIT is also used as a performance measure and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Operations. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and Duke Energy believes its investors use consolidated EBIT as a supplemental measure to evaluate Duke Energy’s consolidated results of operations from continuing operations.

Components of EBIT and Reconciliation of Operating Income to Net Income (in millions)

	Three Months Ended March 31,
	2004		2003
Operating income	$	433	$	889
Other income and expenses		59		74
EBIT		492		963
Interest expense		356		326
Minority interest expense		38		50
Earnings from continuing operations before income taxes		98		587
Income tax expense from continuing operations		33		195
Income from continuing operations		65		392
Income (loss) from discontinued operations, net of tax		246		(5	)
Income before cumulative effect of change in accounting principle		311		387
Cumulative effect of change in accounting principle, net of tax and minority interest		—		(162	)
Net income	$	311	$	225

EBIT should not be considered an alternative to, or more meaningful than, net income or operating cash flow as determined in accordance with GAAP. Duke Energy’s EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

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

13

Business Segment Data (in millions)

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			EBIT
Three Months Ended March 31, 2004
Franchised Electric	$	1,266	$	5		$	1,271		$	424
Natural Gas Transmission		982		56			1,038			398
Field Services		2,317		58			2,375			92
Duke Energy North America		627		29			656			(557	)
International Energy		154		—			154			29
Crescent		195		—			195			60
Total reportable segments		5,541		148			5,689			446
Other		304		40			344			(5	)
Eliminations and minority interests		—		(188	)		(188	)		49
Interest income		—		—			—			7
Foreign currency remeasurement loss		—		—			—			(5	)
Total consolidated	$	5,845	$	—		$	5,845		$	492
Three Months Ended March 31, 2003
Franchised Electric	$	1,247	$	4		$	1,251		$	454
Natural Gas Transmission		879		89			968			423
Field Services		2,082		468			2,550			30
Duke Energy North America		1,308		88			1,396			23
International Energy		172		—			172			40
Crescent		23		—			23			—
Total reportable segments		5,711		649			6,360			970
Other		461		56			517			(48	)
Eliminations and minority interests		—		(705	)		(705	)		43
Interest income		—		—			—			2
Foreign currency remeasurement loss										(4	)
Total consolidated	$	6,172	$	—		$	6,172		$	963

14

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)

	March 31, 2004			December 31, 2003
Franchised Electric	$	15,874		$	16,088
Natural Gas Transmission		16,356			16,384
Field Services		6,776			6,417
Duke Energy North America		7,932			9,184
International Energy		4,521			4,550
Crescent		1,610			1,653
Total reportable segments		53,069			54,276
Other		2,653			2,585
Eliminations		(371	)		(658	)
Total consolidated assets	$	55,351		$	56,203

Segment assets include goodwill of $3,932 million at March 31, 2004 and $3,962 million at December 31, 2003, with $3,194 million at March 31, 2004 allocated to Natural Gas Transmission, $492 million to Field Services, $238 million to International Energy and $7 million to Crescent. The decrease of $30 million was related solely to foreign currency exchange rate fluctuations of $29 million at Natural Gas Transmission and $1 million at Field Services.

10. Risk Management Instruments

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

Derivative Portfolio Carrying Value (in millions)

	March 31, 2004			December 31, 2003
Hedging	$	669		$	424
Trading		150			177
Undesignated		(413	)		(215	)
Total	$	406		$	386

The amounts in the table above represent the combination of amounts presented as assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Energy’s Consolidated Balance Sheets. All amounts in the table represent fair value except that the net asset amounts shown for hedging include assets of $245 million as of March 31, 2004 and $267 million as of December 31, 2003, that were frozen at Duke Energy’s initial application of the normal purchases and normal sales exception to its forward power sales contracts as of July 1, 2001. These balances will reduce upon settlement of the associated contracts.

11. Regulatory Matters

FERC Orders No. 2004 and 2004-A (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: (i) restrictions on how companies and their affiliates interact and share information, including corporate governance information, and (ii) expansion of coverage to affiliated gatherers, processors and intrastate and Hinshaw pipelines. On April 16, 2004, the FERC issued Order 2004-A adopting revised standards of conduct governing information flow between Transmission Providers and their “energy

15

affiliates”. Order 2004-A accommodates unique corporate governance issues raised by Duke Energy’s corporate structure and clarifies provisions governing information flows for governance purposes. The FERC also clarified the expanded coverage of the rules to gatherers, processors and intrastate and Hinshaw pipelines. Duke Energy will be implementing compliance programs to meet the requirements of the orders related to information flow and governance processes. Duke Energy expects to be in full compliance with the orders, including significant training and information posting requirements, by the September 1, 2004 deadline, and expects the orders 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, excluding the other joint owners of the Catawba Nuclear Station: those rates are set through contractual agreements.

In 2002, the state of North Carolina passed clean air legislation that includes provisions that freeze electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007 (rate freeze period), subject to certain conditions, in order for certain North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state’s coal-fired power plants over the next ten years. Included in the legislation are provisions that allow electric utilities, including Duke Energy, to accelerate the recovery of these compliance costs by amortizing them over seven years (2003-2009). Franchised Electric’s amortization expense related to this clean air legislation was $16 million for the first quarter of 2004 and $17 million for the first quarter of 2003. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized within certain limits, although the legislation requires that a minimum of 70% of the total estimated cost of $1.5 billion be amortized within the rate freeze period.

In 2001, the NCUC and the PSCSC began a joint investigation, along with the Public Staff of the NCUC, regarding certain 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 for reporting periods 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 changes in the accounting 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 October 2003 and November 2003 respectively. 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 related to the settlement agreement to the North Carolina Court of Appeals. On February 17, 2004, a panel of the North Carolina Court of Appeals unanimously affirmed the NCUC’s decision. CUCA has since filed a request with the Supreme Court of North Carolina for review of the Court of Appeals’ decision.

In 2002, the NCUC issued an order denying a petition by CUCA to initiate a general rate proceeding and dismissing its complaint alleging unjust and unreasonable rates charged by Duke Power. CUCA appealed this order to the North Carolina Court of Appeals and on February 17, 2004, a panel of the Court unanimously ruled that the NCUC’s denial of CUCA’s petition and complaint was proper and therefore affirmed the NCUC’s order. On March 22, 2004, CUCA filed a request with the Supreme Court of North Carolina for review of the Court of Appeals’ decision.

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

16

1, 2004 through December 31, 2005. The settlement agreement will likely be filed with the NEB for approval in the second quarter of 2004.

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 is in the process of implementing those rates.

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

12. 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 or contaminated sites similar to others in the energy industry. These include some properties that are part of ongoing Duke Energy operations, as well as 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. They are managed in conjunction with the relevant federal, state and local agencies. These sites or matters vary, for example, with respect to site conditions and location, remedial requirements, sharing of responsibility by other entities, and complexity. Certain matters can involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, whereby Duke Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share any liability associated with contamination with other potentially responsible parties, and Duke Energy may benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of the respective business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

Air Quality Control. In 1998, the Environmental Protection Agency (EPA) issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans (SIPs) to significantly reduce emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various states, industry and other interests, including Duke Energy 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 deadline for implementation of 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 these revisions. Duke Energy has incurred approximately $633 million in capital costs for emission controls through March 2004 for compliance with the EPA’s rule. Management estimates that Duke Energy’s remaining capital expenditures to complete the installation of emission controls needed to comply with the EPA’s rule will be approximately $25 million. These remaining expenditures will be incurred by Duke Power in 2004.

Global Climate Change. The United Nations-sponsored Kyoto Protocol prescribes specific greenhouse gas emission reduction targets to developed countries as a response to concerns over global warming and climate change, with a focus on lowering such emissions at the source, including among others fossil-fueled electric power generation and natural gas operations. In 2001 President George W. Bush declared that the U.S. would not ratify the Kyoto Protocol. Canada is presently the only country in which Duke Energy has assets that would have a greenhouse gas reduction obligation under the Kyoto Protocol. If Russia ratifies the Kyoto Protocol, it will enter into force and Canada will be obligated to reduce its average greenhouse gas emissions to 6% below 1990 levels over the period 2008 to 2012. The Canadian government is in the process of developing an implementation plan that includes a carbon dioxide (CO2) cap and trade program for large industrial emitters (LIE), and Parliament is expected to consider authorizing legislation by the end

17

of 2004. If an LIE program is enacted, then all of Duke Energy’s Canadian operations would likely be subject to such a program, with compliance options ranging from purchase of CO2 emissions credits to actual emissions reductions at the source, or a combination of strategies. Canada’s new Prime Minister, Paul Martin, has voiced some questions regarding Canadian climate change strategy, and intends to review it this year. Canadian carbon emissions management policy could change as a result, or if the Kyoto Protocol does not enter into force. The final outcome is still highly uncertain.

In the U.S., administration 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 and there are presently no federal mandatory greenhouse gas reduction requirements. The likelihood of any federal mandatory CO2 emissions reduction regime being enacted in the near future, or the specific requirements of any such regime that were to become law, is highly uncertain. Some states are contemplating or have taken steps to manage greenhouse gas emissions, and while a number of states in the Northeast and far West recently began discussing the possible implementation of regional greenhouse gas reduction programs in the future, the outcome of such discussions is very uncertain. To the extent that a Kyoto Protocol emissions reductions regime comes into legal effect, or that significant greenhouse gas emissions reduction policies are legally adopted or promulgated in non-Kyoto jurisdictions, including the U.S. or its various states, such mandatory emissions reduction 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 stays abreast of and engaged in the greenhouse gas policy developments of the countries, states and regions in which it operates, and will continue to assess and respond to their potential implications for Duke Energy’s business operations in the U.S., Canada and around the world.

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 $89 million as of March 31, 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 some of its current and former sites and certain other environmental matters. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

Litigation

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 August, 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

18

trial against Duke Energy in light of the legal standards established by the Court in its August 2003 order. The judgment reflects that Duke Energy did not violate the NSR program under the CAA. The Court’s order also dismissed with prejudice the state law-based claims of the government. The government and the three intervener environmental groups have the right to appeal the judgment to the U.S. 4^th Circuit Court of Appeals. Based on the current rulings by the 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. Commencing in November 2000, plaintiffs have filed 29 lawsuits in state and federal courts in California and Montana against numerous other energy companies, including Duke Energy affiliates, and current and former Duke Energy executives. Most of these suits seek class action certification on behalf of purchasers of electric and/or natural gas energy 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 various state and/or federal antitrust, unfair business practices, and other laws. Plaintiffs in certain cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications, and unlawfully exchanging information, resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants. To date, eight suits have been dismissed on filed rate and federal preemption grounds. Plaintiffs are appealing the dismissals. One suit was dismissed voluntarily. While several of these cases have been pending for a significant period of time, these matters still are in very early stages. 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.

Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (SCE) have initiated arbitration proceedings regarding disputes with Duke Energy Trading and Marketing, LLC (DETM) relating to amounts owed in connection with the termination of bilateral power contracts between the parties in early 2001. PG&E seeks in excess of $25 million from DETM pursuant to a disputed “true-up” agreement between the parties. SCE disputes DETM’s termination calculation and seeks in excess of $80 million.

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 U.S. during 2000 and 2001. In the 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 December 2002, the presiding administrative law judge in the FERC refund proceedings issued preliminary estimates that indicated DETM had refund liability of approximately $95 million.

On March 26, 2003, the FERC issued staff recommendations and an order relating to the refund proceeding and investigations into the causes of high wholesale electricity prices in the western U.S. 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 result in an increase in the total aggregate refund amount for all generators from $1.8 billion to at least $3.3 billion. The March 26 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 are challenging both the amount and availability of the credit. The FERC has not ruled on the gas credit issues. The FERC initially ordered the California Power Exchange (CalPX) and the California Independent System Operator (CAISO) to calculate the refund amounts (before taking into account any fuel cost credits) by mid-March 2004. Subsequent filings by CalPX and CAISO indicate that they will not complete these calculations until several months after the March 2004 deadline. Duke Energy continues to maintain a reserve in the amount of $90 million relating to the refund exposure, and while future FERC rulings could give rise to exposure exceeding the reserve, Duke Energy believes the reserve amount is appropriate based on information known at this time.

19

In late June 2003, the FERC issued an Order to Show Cause concerning Enron-type gaming behavior and a companion order requiring suppliers, including DETM, to justify bids in the CAISO and CalPX markets made above the level of $250 per megawatt during the period May 1, 2000 through October 1, 2000. On December 19, 2003, the FERC Staff and Duke Energy announced two agreements to resolve all matters at issue in both of these orders. Duke Energy agreed to pay up to $4.59 million to the benefit of 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 have sought review of the FERC’s ruling on this agreement from the 9th Circuit U.S. Court of Appeals. On April 19, 2004, the administrative law judge reviewing the remaining agreement issued a certification approving the settlement and rejecting the California parties’ objections. That agreement will now be submitted to the FERC for review. These agreements will resolve all California related matters pending before the FERC except for the ongoing refund proceeding involving all participants in the California market.

At the state level, the California Public Utilities Commission, 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 some Duke Energy entities 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 November 2002 seeking, in general, information relating to possible manipulation of the electricity markets in California, including potential antitrust violations. Duke Energy is cooperating with these governmental entities in connection with their investigations. Duke Energy cannot predict the outcome of these investigations.

Trading Related Litigation. Beginning in April 2002, 17 shareholder class-action lawsuits were filed against Duke Energy: 13 in the United States District Court for the Southern District of New York and four in the United States District Court for the Western District of North Carolina. These lawsuits arose out of allegations that Duke Energy improperly engaged in “round trip” trades which resulted in an alleged overstatement of revenues over a three-year period. By November 2003, the two federal courts had dismissed all 17 lawsuits. Plaintiffs in the New York cases have appealed the dismissal order to the 2nd Circuit United States Court of Appeals. Duke Energy intends to vigorously defend against this appeal. By letter dated April 16, 2004, Duke Energy received notice that a shareholder has reactivated a litigation demand previously sent to Duke Energy in May 2002. This demand arises out of the same issues raised in the dismissed shareholder lawsuits. The notice states that the shareholder intends to initiate derivative shareholder litigation within 90 days from the date of the letter. Duke Energy is reviewing the demand and will respond appropriately.

Since August 2003, plaintiffs have filed three class action lawsuits brought on behalf of entities who bought and sold natural gas futures and options contracts on the NYMEX during the years 2000 through 2002 in federal district court for the Southern District of New York. The lawsuits initially named Duke Energy as a defendant, along with numerous other entities. In the latest consolidated complaint, the plaintiffs dropped Duke Energy from the cases and added DETM as a defendant. Plaintiffs claim defendants violated the Commodities Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. These cases are in very early stages. It is not possible to predict 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.

Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the 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 mid-October 2002 that the SEC formalized its trading-related investigation. Duke Energy is cooperating with the SEC in this investigation, which remains open and the outcome of which Duke Energy cannot predict. On April 21, 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI

20

Management Inc., 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.” The indictments further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. In statements made by the U.S. Attorney’s office, Duke Energy was characterized as a victim in this activity and was commended 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/Citrus Trading Corporation (Citrus). Duke Energy LNG Sales, Inc. (Duke LNG) claims in this 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. On July 11, 2003, the arbitration panel issued its Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping, rendering them liable to Duke LNG for any resulting damages. The arbitration panel also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. In July 2003, Sonatrading terminated the LNG Agreements and seeks in the arbitration to recover resulting damages from Duke LNG. The damages phase of this proceeding has not yet been scheduled.

In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. In March 2003, Citrus filed a lawsuit in Texas against Duke LNG (now pending in federal 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 a loss of LNG supply. Following the commencement of the Citrus litigation, Duke LNG terminated the Citrus Agreement and filed a counterclaim in the Texas action asserting that Citrus breached the terms of the Citrus Agreement by, among other things, failing to provide sufficient security for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach entitling Citrus to terminate the agreement and recover damages. On March 16, 2004, Citrus filed suit against PanEnergy Corp in the a Harris County, Texas district court alleging that PanEnergy is financially responsible for losses incurred by Citrus as a result of Duke LNG’s alleged breaches. That state court action has been removed to federal court and will likely be consolidated with the original Citrus lawsuit. No trial date has been set for these matters and discovery is proceeding. 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. Additional affiliates have filed for bankruptcy since that date. Certain affiliates of Duke Energy 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 mid-November 2002, various Enron trading entities demanded payment from DETM and Duke Energy Merchants, LLC (DEM) for certain energy commodity sales transactions without regard to any set-off rights. In December 2002, 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 November 2003, DETM, DEM and other Duke Energy affiliates entered into an agreement in principle with Enron and its

21

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 final. The terms of the agreement are confidential and the financial results of the agreement will be recorded in the second quarter of 2004, which Duke Energy estimates will be a net gain of approximately $130 million due to the write-off of net payables to Enron reflected on the March 31, 2004 Consolidated Balance Sheet.

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. 3946231 and DTMSI are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil claims that DETMI and DTMSI engaged in allegedly wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of the agreements and fiduciary duties relating to the Ventures. ExxonMobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages. These amounts are not clearly quantified in the arbitration demand.Duke Energy will rigorously defend against ExxonMobil’s claims and intends to file counterclaims asserting that ExxonMobil breached its venture obligations and other contractual obligations.

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. The arbitration panel has been selected and discovery has commenced. An arbitration hearing is expected in 2004.

These matters are in very early stages. It is not possible to predict with certainty whether Duke Energy or any affiliated entity will incur any liability as a result of these matters or, with respect to the latest arbitration, to estimate the damages, if any, that might be incurred in connection with that matter.

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 as well as estimated amounts for future claims not recoverable under such policy. The insurance policy, combined with amounts covered by self-insurance reserves, provides for claims paid up to an aggregate of $1.6 billion. Duke Energy conducted another review in 2003 and continues to believe the estimated claims relating to this exposure will not exceed such amount. Duke Energy is uncertain as to the timing of when claims will be received, and portions of the estimated claims 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 result in changes in the estimates of the injuries and damages liability and insurance recoveries. Such changes could result in, over time, a difference from the amount 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 not have a 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, 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.

22

13. Guarantees and Indemnifications

Duke Energy and certain of 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) in which DCS will design, construct, operate and deactivate a MOX fuel fabrication facility (the MOX FFF). The domestic MOX fuel project was prompted by an agreement between the U.S. 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 March 31, 2004, Duke Energy Corporation, through its indirect wholly owned subsidiary, Duke Project Services Group, Inc. (DPSG), held a 40% ownership interest in DCS. Additionally, Duke Power has entered into a subcontract with DCS (the Duke Power Subcontract) to prepare the McGuire and Catawba nuclear reactors (the Nuclear Reactors) for use of the MOX fuel and to provide for certain terms and conditions applicable to the purchase of MOX fuel produced at the MOX FFF for use in the Nuclear Reactors.

DPSG and the other owners of DCS have issued a guarantee to the DOE (the DOE Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to the DOE all of DCS’ payment and performance obligations under the Prime Contract. The Prime Contract consists of a “Base Contract” phase and four option phases. The DOE has the right to extend the term of the Prime Contract to cover the four option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. Each of the four option phases will be negotiated separately, as the time for exercising each option phase becomes due under the Prime Contract. If the DOE does not exercise its right to extend the term of the Prime Contract to cover any or all of the option phases, DCS’ performance obligations under the Prime Contract will end upon completion of the then-current performance phase. Additionally, the DOE has the right to terminate the Prime Contract for convenience at any time. Under the Base Contract phase, which covers the design of the MOX FFF and design modifications to the Nuclear Reactors, DCS is to receive cost reimbursement plus a fixed fee. The first option phase includes the modification of Nuclear Reactors and related Duke Power facilities, and provides for DCS to receive cost reimbursement plus an incentive fee. The second option phase includes the construction and cold startup of the MOX FFF, and provides for DCS to receive cost reimbursement plus an incentive fee. The third option phase provides for taking the MOX FFF from cold to hot startup, operation of the MOX FFF, and irradiation of the MOX fuel in the Nuclear Reactors; and provides for DCS to receive a cost reimbursement plus an incentive fee through hot startup and, thereafter, cost-sharing plus a fee. The fourth option phase involves DCS’ deactivation of the MOX FFF in exchange for a fixed price payment. In September 2003, the DOE exercised its right to extend the term of the Prime Contract to cover the first option phase and DCS and the DOE agreed to add the related terms and conditions to the Prime Contract. As of March 31, 2004, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and the first option phase.

Additionally, DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) under which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ payment and performance obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. The Duke Power Subcontract consists of a “Base Subcontract” phase and three option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the three 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. Under the Base Subcontract phase, Duke Power will perform technical and regulatory work required to prepare the Nuclear Reactors to use MOX fuel and will receive cost reimbursement plus a fixed fee. The first option phase includes Duke Power’s modification of the Nuclear Reactors and related

23

Duke Power facilities, and provides for Duke Power to receive cost reimbursement plus a fee. The second option phase includes Duke Power performance of additional technical and regulatory work, and provides for Duke Power to receive cost reimbursement plus a fee. The third option phase provides for Duke Power to purchase from DCS MOX fuel produced at the MOX FFF for use in the Nuclear Reactors, at discounts to prices of equivalent uranium fuel, over a 15-year period starting upon completion of the second option phase. In October 2003, DCS exercised its right to extend the term of the Duke Power Subcontract to cover the first option phase and Duke Power and DCS agreed to add the related terms and conditions to the Duke Power Subcontract. As of March 31, 2004, DCS’s performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase.

The cost reimbursement nature of DCS’ commitment under the Prime Contract and the Duke Power Subcontract limits the exposure of DCS. Credit risk to DCS is limited in that the Prime Contract is with the DOE, a U.S. governmental entity. DCS is under no obligation to perform any contract work under the Prime Contract before funds have been appropriated from the U.S. Congress with respect to such work.

Duke Energy is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee and the Duke Power Guarantee due to the uncertainty of whether: (i) the DOE will exercise its options under the Prime Contract; (ii) 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 (iii) the U.S. Congress will authorize funding for DCS’ work under the Prime Contract. Even though neither the DOE Guarantee nor the Duke Power Guarantee provide for a specific limitation on a guarantor’s payments, any liability of DPSG under the DOE Guarantee or the Duke Power Guarantee is directly related to and limited by the terms and conditions contained in the Prime Contract and the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Prime Contract, respectively. DPSG also has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee or the Duke Power Guarantee in excess of its proportional ownership percentage of DCS.

On April 15, 2004, DCS and the DOE entered into an amendment to the Prime Contract that, among other things, clarified that the DOE Guarantee solely covers the guarantors’ obligations to reimburse the DOE, in the event 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.

As of March 31, 2004, Duke Energy had no liabilities recorded on its Consolidated Balance Sheet for the above mentioned MOX guarantees.

Other Guarantees and Indemnifications.Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of March 31, 2004 was approximately $575 million. Of this amount, approximately $300 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $25 million of the performance guarantees expire between 2004 and 2005, approximately $300 million expires in 2006 and thereafter, with the remaining performance guarantees having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to certain of the D/FD project owners, which guarantee 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 D/FD partners is responsible for 50% of any payments to be made under these guarantee contracts.

Westcoast Energy, Inc. (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. These performance guarantees require Westcoast to make payment to the

24

guaranteed third party upon the failure of the unconsolidated entity to make payment under certain 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 these performance guarantees as of March 31, 2004 was approximately $50 million. Of these guarantees, approximately $30 million expire from 2004 to 2007, with the remainder expiring after 2007 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 under the letter of credit due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. These letters of credit principally expire in 2004. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of March 31, 2004 was approximately $425 million. Of this amount, approximately $325 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities.

Duke Capital has guaranteed the issuance of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of March 31, 2004, Duke Capital had guaranteed approximately $100 million of outstanding surety bonds related to obligations of non- wholly owned entities. 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 certain guarantees of debt associated with non-consolidated entities and less than wholly-owned entities. In the event that non-consolidated entities or less than wholly-owned entities default on the debt payments, Natural Gas Transmission or International Energy would be required to perform under the guarantees and make payment on the outstanding debt balance of the non-consolidated entity. As of March 31, 2004, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly-owned entities, with no contractual expiration. International Energy was the guarantor of approximately $25 million of debt associated with less than wholly-owned entities, which principally expire in 2004.

Duke Energy has certain guarantees issued 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. In connection with the sale of DE&S, Duke Energy has received back-to-back indemnification from the buyer indemnifying Duke Energy for any amounts paid by Duke Energy related to the DE&S guarantees. In connection with the sale of DukeSolutions, Duke Energy received indemnification from the buyer for the first $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 certain 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 as to such losses up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed in the foregoing sentence). 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 guaranteed agreements contain no limits on potential liability.

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 indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements 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 dollar amount to an unlimited 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

25

payments under these indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities.

As of March 31, 2004, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial both individually and in the aggregate.

14. New Accounting Standards

The following new accounting standards have been adopted by Duke Energy subsequent to March 31, 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.” The amendment reflects decisions made by the FASB and the Derivative Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 are to be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The provisions of SFAS No. 149 that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 continue to be applied based upon 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 policy for accounting 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, including following any modifications to these 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, such financial 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 on 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 non-controlling interest in a limited life entity in Bolivia, whereby the entity is required to be liquidated 99 years after formation. 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. At March 31, 2004 the fair value of the entity’s non-controlling interest of approximately $40 million approximates its carrying 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 changes could be made by the FASB during such future deliberations. Therefore, Duke Energy is not able to conclude as to whether such future changes would be likely to 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 is the party that 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 certain provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46 and certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46.

The provisions of FIN 46 are immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and the provisions of FIN 46R are required to be applied to such 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 adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect

26

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 $130 million as of March 31, 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 the trust subsidiaries that issued the trust preferred securities. Since Duke Energy is not the primary beneficiary of such trust subsidiaries, these entities have been deconsolidated in the accompanying Consolidated Financial Statements. This deconsolidation resulted in Duke Energy reflecting affiliate debt to the trusts 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 subsequent to December 31, 2003. Additionally, Duke Energy has a significant variable interest in, but is not the primary beneficiary of, DCS due to certain guarantee obligations as discussed in Note 13. As further discussed in Note 13, Duke Energy’s maximum exposure to loss as a result of its variable interest in DCS cannot be quantified.

Various changes and clarifications have been made by the FASB to the provisions of FIN 46 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 the Consolidated Financial Statements of Duke Energy.

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 in the arrangements are required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations 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. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In July 2003, the EITF reached consensus in EITF Issue No. 03-11 that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances and the economic substance of the transaction. In analyzing the 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.

27

The following new accounting standards have been issued by the authoritative accounting body, but have not yet been adopted or fully adopted by Duke Energy as of March 31, 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 postretirement plans, such as the following: (1) the long-term rate of return on plan assets along with narrative discussion of basis for selecting the rate of return used; (2) 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 by each major asset category and the actual allocation percentage at the measurement date; (3) 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; (4) current best estimate of range of contributions expected to be made in following year; (5) the accumulated benefit obligation for defined benefit pension plans; and (6) disclosure of measurement date utilized. Additionally, interim reports require certain additional disclosures related to the components of net periodic pension cost recognized and 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 postretirement plans as required by previous accounting standards. Except as discussed below, 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 March 31, 2004. The disclosure provisions of estimated future benefit payments will be effective for Duke Energy for the year ending December 31, 2004.

FASB Staff Position (FSP) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”In January 2004, the FASB staff issued FSP FAS 106-1, which allows a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), which became law in December 2003. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. FSP FAS 106-1 allows a sponsor to defer recognizing the effects of the Act in accounting for its postretirement benefit plans under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” until further authoritative accounting guidance is issued. Duke Energy has a measurement date of September 30 for its SFAS No. 106 postretirement benefit plans and has elected to defer application of SFAS No. 106 to the provisions of the Act under the guidance given in FSP FAS 106-1. Therefore, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost contained in the Duke Energy Consolidated Financial Statements do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and such guidance, when issued, could require a change to previously reported information. Duke Energy is still reviewing the potential impacts of the Act on its postretirement benefit plans including whether the benefits under its plans are actuarially equivalent to Medicare Part D.

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 2004 and may require restatement of previously reported EPS measures if any changes to the calculation of EPS are required pursuant to the consensus. Duke Energy is currently assessing the impacts of this EITF Issue on its consolidated calculation of EPS.

15. Subsequent Events

As disclosed in Note 12 to the Consolidated Financial Statements, Subsequent Events, in Duke Energy’s Form 10-Q for June 30, 2003, Duke Energy announced the sale of a 25% undivided interest in the Duke Energy Vermillion facility. In May 2004, the sale of the 25% undivided interest in the Vermillion facility was completed for approximately $44 million. A loss on the sale of approximately $18 million was recorded in the third quarter of 2003. Duke Energy will continue to own the remaining 75% interest in the facility.

As disclosed in Note 23 to the Consolidated Financial Statements, Subsequent Events, in Duke Energy’s Form 10-K for December 31, 2003, DEFS announced that it had entered into an agreement to acquire

28

gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips. In May 2004, the acquisition of these assets was completed for approximately $74 million.

For information on subsequent events related to debt and credit facilities, see Note 5. For information related to the sale of International Energy’s Asia Pacific power generation and natural gas transmission businesses, and the sale of all of Duke Energy’s merchant generation assets in the Southeastern U.S., see Note 8. For information related to the Enron bankruptcy, see Note 12.

29

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

INTRODUCTION

Management’s Discussion and Analysis should be read in connection 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 its 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 Form 10-K for the year ended December 31, 2003.

RESULTS OF OPERATIONS

Overview of Drivers and Variances

For the three months ending March 31, 2004, earnings available for common stockholders were $309 million, or $0.34 per basic and diluted share. For the three months ending March 31, 2003, earnings available for common stockholders were $222 million, or $0.25 per basic and diluted share. Significant items that contributed to the increased results in 2004 included:

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

• Charges in 2003 related to changes in accounting principles of $162 million, net of tax and minority interest

• Increased earnings at Field Services due to the favorable effects of commodity prices, net of hedging, and improved results from trading and marketing activities

• Increased earnings at Crescent Resources, LLC (Crescent) due to increased land and commercial sales

These items were partially offset by:

• An approximate $360 million pre-tax charge in 2004 associated with the sale of Duke Energy North America’s (DENA’s) Southeastern plants (see Note 8 to the Consolidated Financial Statements)

• A $93 million ($87 million after minority interest) mark-to-market loss at DENA in 2004 as a result of changes in power and gas prices

On a consolidated and segment reporting basis, first quarter 2004 results may not be indicative of the full year. Management has not changed its financial outlook for the remainder of the year for Duke Energy, nor the estimated Consolidated Earnings Before Interest and Taxes from continuing operations (EBIT) growth targets for any of the business segments over the next three years.

Consolidated Operating Revenues

Consolidated operating revenues for the three months ended March 31, 2004 decreased $327 million, compared to the same period in 2003. This change was driven by a $402 million decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, due primarily to a decrease at DENA related to decreased sales volumes as a result of the wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with ExxonMobil Corporation) and decreased gas prices; and a decrease in revenues at Duke Energy Merchants, LLC (DEM), due to the decision in 2003 to exit the

30

refined products and NGL business at DEM. Partially offsetting these decreases were increased property sales at Crescent and increased third party revenues at Field Services (although Field Services’ segment revenues are down due to decreased intercompany sales, which eliminate on a consolidated basis). Field Services’ third party sales are up due primarily to an increase in gas volumes sold, and an increase in NGL prices and volumes.

Partially offsetting the decrease in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues was an increase of $103 million in Regulated Natural Gas revenues, due primarily to foreign currency impacts related to the strengthening Canadian dollar.

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

Consolidated Operating Expenses

Consolidated operating expenses for the three months ended March 31, 2004 decreased $211 million, compared to the same period in 2003. Changes in consolidated operating expenses were driven primarily by a $460 million decrease in Natural Gas and Petroleum Products Purchased, due primarily to a decrease in the costs of raw natural gas at Field Services; a decrease in purchases at DEM, due to the decision in 2003 to exit the refined products and NGL business at DEM; and a decrease at DENA related to decreased purchases as a result of the wind-down of DETM and decreased gas prices. Partially offsetting these decreases was an increase related to foreign currency impacts due to the strengthening Canadian dollar.

Partially offsetting the decrease in Natural Gas and Petroleum Products Purchased was a $214 million increase in Operation, maintenance and other, due primarily to an increase in the volume of Crescent’s commercial project and residential developed lot sales in 2004 versus 2003. Also contributing to the increase in Operation, maintenance and other was foreign currency impacts related to the strengthening Canadian dollar.

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

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

Consolidated (losses) gains on sales of other assets for the three months ended March 31, 2004 decreased $340 million, compared to the same period in 2003. The decrease was due primarily to the approximately $360 million loss in 2004 associated with the sale of DENA’s Southeastern plants, as discussed above.

Consolidated Operating Income

For the three months ended March 31, 2004, consolidated operating income decreased $456 million, compared to the same period in 2003, due primarily to decreased operating income at DENA of $581 million. As discussed above, the decrease at DENA was due primarily to the 2004 loss on the sale of DENA’s Southeastern plants, mark-to-market losses due to the disqualification of certain hedges and the wind-down of DETM. The decrease at DENA was partially offset by increased operating income at Field Services, due to the favorable effects of commodity prices, net of hedging, and improved results from trading and marketing activities, and at Crescent, due to increased land and commercial sales.

For a more detailed discussion of these variances, see segment discussions below.

Consolidated Earnings Before Interest and Taxes From Continuing Operations (EBIT)

Changes in consolidated EBIT were primarily driven by the same changes as consolidated operating income, as discussed above. Consolidated EBIT also includes Other Income and Expenses, which only decreased $15 million for the three months ended March 31, 2004, compared to the same period in 2003.

31

For a more detailed discussion of EBIT, see segment discussions below.

Consolidated EBIT is viewed as a non-Generally Accepted Accounting Principles (GAAP) measure under the rules of the Securities and Exchange Commission (SEC). Duke Energy includes EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance for continuing operations. On a segment basis, EBIT excludes discontinued operations and 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. Since the business units do not manage those items, the gains and losses on foreign currency remeasurement associated with cash balances, and third-party 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.

On a consolidated basis, EBIT is also used as a performance measure and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Operations. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and Duke Energy believes its investors use EBIT as a supplemental measure to evaluate Duke Energy’s consolidated results of operations from continuing operations.

Components of EBIT and Reconciliation of Operating Income to NetIncome(in millions)

	Three Months Ended March 31,
	2004		2003
Operating income	$	433	$	889
Other income and expenses		59		74
EBIT		492		963
Interest expense		356		326
Minority interest expense		38		50
Earnings from continuing operations before income taxes		98		587
Income tax expense from continuing operations		33		195
Income from continuing operations		65		392
Income (loss) from discontinued operations, net of tax		246		(5	)
Income before cumulative effect of change in accounting principle		311		387
Cumulative effect of change in accounting principle, net of tax and minority interest		—		(162	)
Net income	$	311	$	225

EBIT should not be considered an alternative to, or more meaningful than, net income or operating cash flow as determined in accordance with GAAP. Duke Energy’s EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

Beginning in 2004, Crescent, formerly part of Other Operations, as defined in Duke Energy’s Annual Report on Form 10-K, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages land holdings primarily in the Southeastern and Southwestern U.S. All other entities previously part of Other Operations and now within

32

Other still remain, primarily: DukeNet Communications, LLC, Duke Energy Merchants, LLC and Duke/Fluor Daniel. Unallocated corporate costs are also recorded in Other in the following table.

EBIT by Business Segment (in millions)

	Three Months Ended March 31,
	2004			2003
Franchised Electric	$	424		$	454
Natural Gas Transmission		398			423
Field Services		92			30
Duke Energy North America		(557	)		23
International Energy		29			40
Crescent		60			—
Total reportable segment EBIT		446			970
Other		(5	)		(48	)
Total reportable segment and other EBIT		441			922
Minority interest expense		50			43
Third-party interest income		7			2
Foreign currency remeasurement gain		(5	)		(4	)
Intercompany EBIT eliminationa		(1	)		—
Consolidated EBIT	$	492		$	963

^a Amounts relate to the elimination of intercompany EBIT that has been reclassified to discontinued operations.

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

Franchised Electric

	Three Months Ended March 31,
(in millions, except where noted)	2004		2003
Operating revenues	$	1,271	$	1,251
Operating expenses		851		813
Operating income		420		438
Other income, net of expenses		4		16
EBIT	$	424	$	454
Sales, Gigawatt-hours (GWh)		21,963		22,043

33

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

Increase (decrease) over prior year	Three Months Ended
Residential salesa	3.4%
General service salesa	2.6%
Industrial salesa	(4.0)%
Wholesale sales	(7.4)%
Total Franchised Electric salesb	(0.4)%
Average number of customers	1.5%

^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 March 31, 2004 as Compared to March 31, 2003

Operating Revenues.Operating revenues for the three months ended March 31, 2004 increased $20 million, compared to the same period in 2003. The increase was driven primarily by:

• A $26 million increase in fuel revenues, driven by increased fuel rates for retail customers due to increased coal costs

• A $12 million increase in GWh sales to retail customers due to favorable weather during the quarter

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

• A $21 million decrease in wholesale power sales due to lower prices ($11 million) and lower volumes ($10 million)

• An $8 million decrease in sales to industrial customers, which continued to decline in North Carolina and South Carolina

Operating Expenses.Operating expenses for the three months ended March 31, 2004 increased $38 million, compared to the same period in 2003. The increase was driven primarily by:

• Increased fuel expenses of $31 million, due primarily to increased coal costs

• Increased nuclear outage costs of $18 million, driven by increased outage days during the period

• Decreased storm costs of $24 million, with $11 million incurred in 2004 compared to $35 million incurred in 2003

Other Income, net of expenses.Other income, net of expenses decreased $12 million for the three months ended March 31, 2004, compared to the same period in 2003. This decrease was driven primarily by a decrease in allowance for funds used during construction, due primarily to large construction projects that were completed in 2003, and a decrease in the return on deferred costs related to the purchase of capacity from the joint owners of the Catawba Nuclear Station.

EBIT. EBIT for the three months ended March 31, 2004 decreased $30 million, compared to the same period in 2003. This decrease resulted primarily from increased expenses related to planned nuclear outages, coupled with decreased sales to wholesale and industrial customers. These changes were partially offset by increased sales to retail customers due to favorable weather and continued growth in the number of residential and general service customers and decreased storm costs.

34

Natural Gas Transmission

	Three Months Ended March 31,
(in millions, except where noted)	2004		2003
Operating revenues	$	1,038	$	968
Operating expenses		638		567
Operating income		400		401
Other income, net of expenses		6		35
Minority interest expense		8		13
EBIT	$	398	$	423
Proportional throughput, TBtua		1,089		1,082

^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 March 31, 2004 as Compared to March 31, 2003

Operating Revenues.Operating revenues for the three months ended March 31, 2004 increased $70 million, compared to the same period in 2003. This increase was driven primarily by:

• A $91 million increase due to foreign exchange favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar, partially offset by currency impacts to expenses

• A $12 million increase from recovery of natural gas commodity costs that are passed through to customers without mark-up at Union Gas Limited (Union Gas). This amount is offset in expenses.

• An $11 million increase from completed and operational business expansion projects in the U.S.

• A $31 million decrease as a result of the sale of Empire State Pipeline in February 2003 and Pacific Northern Gas Limited in December 2003

Operating Expenses.Operating expenses for the three months ended March 31, 2004 increased $71 million, compared to the same period in 2003. This increase was driven primarily by:

• A $65 million increase caused by foreign exchange impacts

• A $13 million increase related to project development costs that were capitalized in 2003

• A $12 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

• A $24 million decrease as a result of operations sold in 2003

Other Income, net of expenses.Other income, net of expenses decreased $29 million for the three months ended 2004, compared to the same period in 2003. This decrease was driven primarily by:

• A $12 million decrease in equity earnings as a result of investments sold in 2003

• A $16 million decrease as a result of prior year gains on sale, primarily the gain on the sale of Natural Gas Transmission’s limited partnership interests in Northern Border Partners L.P. in January 2003

EBIT. EBIT for the three months ended March 31, 2004 decreased $25 million, compared to the same period in 2003, primarily as a result of gains from asset sales recorded in the prior year first quarter, foregone earnings from various assets sold during 2003, project development costs capitalized in 2003 and warmer weather at Union Gas (the Canadian gas distribution business) in 2004. Partially offsetting these decreases were contributions from U.S. business expansions and foreign exchange EBIT impacts from the strengthening Canadian currency.

35

Field Services

	Three Months Ended March 31,
(in millions, except where noted)	2004		2003
Operating revenues	$	2,375	$	2,550
Operating expenses		2,249		2,509
Operating income		126		41
Other income, net of expenses		18		15
Minority interest expense		52		26
EBIT	$	92	$	30
Natural gas gathered and processed/transported, TBtu/d a		7.3		7.7
NGL production, MBbl/d b		356.7		367.9
Average natural gas price per MMBtuc, d, e	$	5.69	$	6.59
Average NGL price per gallond, e	$	0.59	$	0.58

^a Trillion British thermal units per day

^b Thousand barrels per day

^c Million British thermal units

^d Index based market price

^e Does not reflect results of commodity hedges

Three Months Ended March 31, 2004 as Compared to March 31, 2003

Operating Revenues.Operating revenues for the three months ended March 31, 2004 decreased $175 million, compared to the same period in 2003. This decrease was driven primarily by:

• A $185 million decrease due to a $0.90 per MMBtu decrease in average natural gas prices

• A $125 million decrease from lower throughput related to reduced raw natural gas supply volume. Raw natural gas supply volume had decreased due to reservoir decline exceeding new supply from drilling activity and increased plant downtime due to maintenance.

• A $50 million increase related to higher NGL sales volumes, due primarily to wholesale marketing increases, partially offset by lower NGL production due to throughput decline and plant maintenance

• A $35 million increase from trading and marketing net margin due primarily to higher margins from natural gas trading and marketing

• A $30 million increase related to cash flow hedging which reduced revenues by approximately $45 million for the three months ended March 31, 2004 and $75 million for the three months ended March 31, 2003

• A $15 million increase due to a $0.01 per gallon increase in average NGL prices

Operating Expenses.Operating expenses for the three months ended March 31, 2004 decreased $260 million, compared to the same period in 2003. This decrease was driven primarily by:

• A $185 million decrease in costs of raw natural gas

• A $65 million decrease from lower throughput of raw natural gas supply volume

• A $10 million decrease in operating, and general and administrative expenses due to lower repairs, maintenance, and labor and benefits.

Minority Interest Expense.Minority interest at Field Services increased $26 million for the three months ended March 31, 2004, compared to the same period in 2003, due to increased earnings from Duke Energy Field Services, LLC (DEFS), Duke Energy’s joint venture with ConocoPhillips. The increase in minority interest expense 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.

36

EBIT. EBIT for the three months ended March 31, 2004 increased $62 million, compared to the same period in 2003. As discussed above, the increase primarily resulted from the favorable effects of commodity prices and improved results from trading and marketing activities.

Duke Energy North America

	Three Months Ended March 31,
(in millions, except where noted)	2004			2003
Operating revenues	$	656		$	1,396
Operating expenses		871			1,382
Losses on sales of other assets, net		(352	)		—
Operating (loss) income		(567	)		14
Other income, net of expenses		(4	)		9
Minority interest benefit		(14	)		—
EBIT	$	(557	)	$	23
Actual plant production, GWha		5,461			5,110
Proportional megawatt capacity in operation		15,821			14,156

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

Three Months Ended March 31, 2004 as Compared to March 31, 2003

Operating Revenues.Operating revenues for the three months ended March 31, 2004 decreased $740 million, compared to the same period in 2003. The decrease was driven primarily by:

• A $570 million decrease in natural gas sales due primarily to decreased volumes delivered totaling $314 million as a result of the wind down of DETM , and weaker year on year prices totaling $242 million due primarily to lower average natural gas prices

• A $41 million decrease in overall power revenues due primarily to a $57 million decrease resulting from lower average power sales prices offset by an increase in volumes delivered totaling $16 million

• A $124 million decrease in net trading margin driven primarily by negative mark-to-market margins in 2004 of $93 million. Duke Energy made decisions in 2003 to either terminate construction or attempt to sell certain generation assets that reduced DENA’s anticipated future power generation and sales volumes. Accordingly, certain hedging contracts, that typically served to either fix the price of future power sales or future natural gas fuel purchases, ceased to qualify for hedge accounting and have been subject to mark-to-market accounting during the three months ended March 31, 2004. During the quarter, changes in future power and gas prices have decreased the fair value of these contracts. Duke Energy’s management will continue its focus on reducing exposure to mark-to-market movements.

Operating Expenses. Operating expenses for the three months ended March 31, 2004 decreased $511 million, compared to the same period in 2003. The decrease was driven primarily by:

• A $553 million decrease in gas costs due primarily to decreased natural gas purchases of $313 million primarily as a result of the wind down of DETM and weaker year on year natural gas prices totaling $201 million

• A $48 million increase in overall gas costs due to lower realized value from gas hedges in the current year

• A $5 million decrease in other general and administrative expenses primarily due to workforce reductions in 2003 as a result of the reorganization of the business

37

Losses on Sales of Other Assets, net. Losses on sales of other assets for the quarter ended March 31, 2004 were $352 million, due primarily to a loss associated with the sale of DENA’s Southeastern plants totaling approximately $360 million. (See Note 8 to the Consolidated Financial Statements.)

Other Income, net of expenses. Other income, net of expenses decreased $13 million for the quarter ended March 31, 2004, compared to the same period in 2003. The decrease was driven by lower equity earnings due to the sale of Ref-Fuel in 2003 and foreign currency remeasurement losses associated with DENA’s Canadian business activity in 2004.

Minority Interest Benefit.For the quarter ended March 31, 2004, losses at DETM resulted in a minority interest benefit. DETM’s lower results in 2004 were due to the wind down of the trading and marketing joint venture with ExxonMobil.

EBIT. EBIT for the quarter ended March 31, 2004 decreased $580 million, compared to the same period for 2003. The decrease was due primarily to the approximately $360 million loss associated with the sale of the Southeast plants, the $93 million mark-to-market loss ($87 million after minority interest) as a result of changes in power and gas prices, and lower energy generation margin as a result of lower spark value realization.

International Energy

	Three Months Ended March 31,
(in millions, except where noted)	2004		2003
Operating revenues	$	154	$	172
Operating expenses		131		135
Operating income		23		37
Other income, net of expenses		9		7
Minority interest expense		3		4
EBIT	$	29	$	40
Sales, GWh		4,564		3,969
Proportional megawatt capacity in operation		4,121		4,013

Three Months Ended March 31, 2004 as Compared to March 31, 2003

Operating Revenues.Operating revenues for the three months ended March 31, 2004 decreased $18 million, compared to the same period in 2003. The decrease was driven primarily by lower natural gas sales of $30 million due to the termination of a gas sales contract with Citrus Trading Corporation in April 2003, offset by an increase of $11 million related to higher sales prices under the initial contracts in Brazil. For further information see Note 12 to the Consolidated Financial Statements.

Operating Expenses.Operating expenses for the three months ended March 31, 2004 decreased $4 million, compared to the same period in 2003. The decrease was driven primarily by lower natural gas purchases of $27 million due to the termination of a gas sales contract in April 2003, offset by $19 million of charges associated with the intention to sell the ownership share of Cantarell in Mexico and bad debt expense in Guatemala.

EBIT. EBIT for the three months ended March 31, 2004 decreased $11 million, compared to the same period in 2003. This decrease was due primarily to the $19 million in charges discussed above, partially offset by an $11 million adjustment in 2003 related to revenue recognition at the Cantarell equity

38

investment in Mexico. The remaining portion of the decrease primarily relates to lower results at National Methanol.

Crescent

	Three Months Ended March 31,
(in millions)	2004		2003
Operating revenues	$	195	$	23
Operating expenses		134		23
Operating income		61		—
Minority interest expense		1		—
EBIT	$	60	$	—
Residential developed lot sales	$	32	$	14
Commercial project sales	$	116	$	—
Real estate land sales	$	1	$	2
Land management land sales	$	39	$	2

Three Months Ended March 31, 2004 as Compared to March 31, 2003

Operating Revenues. Operating revenues for the three months ended March 31, 2004 increased $172 million, compared to the same period in 2003. The increase was driven primarily by:

• A $116 million increase in commercial project sales due to the sale of a commercial project in the Washington, DC area

• A $37 million increase in land management or “legacy” land sales due to several large sales closed in the first quarter of 2004 as compared to $2 million closed in the first quarter of 2003

• An $18 million increase in residential developed lot sales due to increased sales at Crescent’s Palmetto Bluff project in Bluffton, South Carolina, Crescent’s LandMar division in northeastern Florida and Crescent’s Lake Keowee projects in northwestern South Carolina

Operating Expenses.Operating expenses for the three months ended March 31, 2004 increased $111 million, compared to the same period in 2003. The increase was driven primarily by:

• A $96 million increase in the cost of commercial project sales due to the sale of a commercial project in the Washington, DC area as noted above

• An $11 million increase in the cost of residential developed lot sales due to increased sales at Crescent’s Palmetto Bluff project and Crescent’s LandMar division as noted above

EBIT. For the three months ended March 31, 2004, EBIT increased $60 million, compared to the same period in 2003. As discussed above, the increase in EBIT was primarily driven by a dramatic increase in legacy land sales, the sale of a commercial project in the Washington, DC area and an increase in residential developed lot sales.

39

Other

	Three Months Ended March 31,
(in millions)	2004			2003
Operating revenues	$	344		$	517
Operating expenses		387			582
Gains on sales of other assets, net		14			—
Operating loss		(29	)		(65	)
Other income, net of expenses		24			17
EBIT	$	(5	)	$	(48	)

Three Months Ended March 31, 2004 as Compared to March 31, 2003

Operating Revenues. Operating revenues for the three months ended March 31, 2004 decreased $173 million, compared to the same period in 2003. The decrease was driven primarily by a $163 million decrease at DEM due to the decision in 2003 to exit the refined products and NGL business at DEM.

Operating Expenses.Operating expenses for the three months ended March 31, 2004 decreased $195 million, compared to the same period in 2003. The decrease was driven primarily by a $196 million decrease at DEM due to the decision in 2003 to exit the refined products and NGL business at DEM.

Gains on Sales of Other Assets, net.Gains on sales of other assets for the three months ended March 31, 2004 was $14 million due primarily to a gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company, an ammonia plant in Trinidad.

EBIT. For the three months ended March 31, 2004, EBIT improved by $43 million, compared to the same period in 2003. The improvement in EBIT was driven primarily by a $47 million EBIT increase at DEM due primarily to the 2004 gains on sales of other assets described above and a 2003 loss of $32 million from certain commodity positions.

Other Impacts on Earnings Available for Common Stockholders

For the three months ended March 31, 2004, interest expense increased $30 million, compared to the same period in 2003. The increase was due primarily to a $14 million decrease in capitalized interest, and expenses of $16 million related to certain 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.” Also contributing to the increase was an $11 million charge related to re-marketing costs associated with the equity units at Duke Capital LLC (Duke Capital, a wholly owned subsidiary of Duke Energy) and a $9 million increase associated with Canadian exchange rates. These increases were offset by a $20 million decrease from net debt reduction, refinancing and lower interest cost in Brazil.

Minority interest expense decreased $12 million for the three months ended March 31, 2004, compared to the same period in 2003. 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 $27 million for the three months ended March 31, 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

40

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 $15 million for the three months ended March 31, 2004 as compared to the same period in 2003. The change was driven by increased earnings at DEFS, offset by decreased earnings at DETM.

Income tax expense from continuing operations decreased $162 million, or 83%, for the three months ended March 31, 2004, compared to the same period in 2003, due primarily to a $489 million, or 83%, decrease in earnings from continuing operations before income taxes.

Income (loss) from discontinued operations increased $251 million for the three months ended March 31, 2004, compared to the same period in 2003. The increase was due primarily to a $238 million, after-tax, gain on sale recorded in the first quarter of 2004 surrounding the sale of International Energy’s Asia Pacific power generation and natural gas transmission business. (See Note 8 to the Consolidated Financial Statements.)

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, due to the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $198 million for the three months ended March 31, 2004, compared to the same period in 2003, due primarily to decreased cash flow from changes in working capital. Cash flow from changes in working capital for the 2004 period was lower than the 2003 period due primarily to less collateral being posted to Duke Energy from counterparties, higher general and administrative related payments and foreign taxes paid. Cash earnings from operations were comparable for the 2004 and 2003 periods.

Investing Cash Flows

Net cash used in investing activities decreased $16 million for the three months ended March 31, 2004, compared to the same period in 2003. Of this decrease, $185 million related to decreased capital and investment expenditures, due primarily to continued lower investments in generating facilities at DENA offset by an increase in investments at Crescent. The increased cash flow from less capital and investment expenditures was offset by a decrease of $140 million in net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable. Proceeds from the sales of equity investments and other assets were $61 million less for the first three months of 2004 compared to the same period in 2003 due primarily to Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline during the first quarter of 2003. Additionally, during the first quarter of 2003, collections on notes receivable were significantly greater than in the first quarter of 2004.

41

For 2004, Duke Energy expects annual capital and investment expenditures to be approximately $2.5 billion, which is an increase of approximately $300 million from the $2.2 billion 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 Form 10-K for December 31, 2003. The increase in projected capital and investment expenditures for 2004 is due largely to the contribution to Duke Energy’s external nuclear decommissioning fund of approximately $262 million in the second quarter of 2004.

Financing Cash Flows and Liquidity

Fixed charges coverage ratio, calculated using SEC guidelines, was 1.4 times for the three months ended March 31, 2004 and 2.6 times for the three months ended March 31, 2003.

Net cash used in financing activities decreased $301 million for the three months ended March 31, 2004 when compared to the same period in 2003. This change is due primarily to redemptions and net paydowns of long-term debt, commercial paper and notes payable of approximately $1.2 billion in 2003. These redemptions and paydowns were partially offset by issuances in 2003 of first and refunding mortgage bonds and other debt of approximately $800 million, the proceeds of which were used to redeem long-term debt and commercial paper. Other net paydowns on commercial paper and notes payable in 2003 were primarily funded through cash proceeds from assets sales in the first quarter of 2003. In 2004 net paydowns were approximately $200 million, which consisted of a $350 million redemption of trust preferred securities offset by issuances of $145 million in short-term debt, primarily commercial paper.

Duke Energy’s cash requirements for 2004 are expected to be funded by cash from operations, the sale of assets and the settlement of the forward stock purchase component of the outstanding Equity Units in May and November of 2004, and are expected to be adequate for funding capital expenditures, dividend payments and planned debt reductions.

Significant Financing Activities. In February 2004, Duke Energy remarketed $875 million of senior notes, due 2006, underlying its Equity Units and reset the interest rate from 5.87% to 4.302%. As this remarketing followed the remarketing contemplated in the original Equity Units issuance, the remarketing transaction had no immediate accounting implications. Subsequent to this remarketing, Duke Energy entered into an exchange transaction with the purchasers of $475 million of remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009 and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with Emerging Issue Task Force (EITF) Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued at 4.302% was considered extinguished. This exchange transaction resulted in a loss of approximately $11 million which is included in interest expense in the Consolidated Financial Statements.

In March 2004, Duke Energy redeemed the entire issue of 7.20% Duke Energy debt to an affiliate due in 2037. The total redemption price was approximately $350 million. 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 April 2004, Duke Energy retired approximately $1.1 billion of debt, including substantially all of the $900 million of debt associated with the Australian operations that have been classified as discontinued operations as of December 31, 2003. The debt associated with the Australian operations had been reclassified to Current and Non-Current Liabilities Associated with Assets Held for Sale at December 31, 2003 and March 31, 2004. 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 Energy announced that on May 28, 2004, it will redeem Duke Energy Series C 6.60% Senior Notes due 2038, with a face value of $200 million. As the securities are being redeemed at par, security holders will receive $25 per each note held, plus accrued interest to the redemption date.

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

Available Credit Facilities and Restrictive Debt Covenants.Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in acceleration of due dates of certain borrowings and/or termination of the agreements. As of March 31, 2004, Duke Energy was in compliance with those covenants. In addition, certain of the credit agreements contain cross-acceleration provisions that may allow for acceleration of payments or termination of the agreements upon: (1) nonpayment or (2) acceleration of other significant indebtedness of the

42

applicable borrower or certain of its subsidiaries. None of the credit agreements contain material adverse change clauses.

Credit Ratings. The credit ratings of Duke Energy, Duke Capital and its subsidiaries have not changed since March 1, 2004 as reported in Duke Energy’s Form 10-K for December 31, 2003 - Financing Cash Flows and Liquidity. The following table summarizes the May 1, 2004 credit ratings from the rating 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 May 1, 2004

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service (DBRS)
Duke Energya	BBB	Baa1	Not applicable
Duke Capital LLCa	BBB-	Baa3	Not applicable
Duke Energy Field Servicesa	BBB	Baa2	Not applicable
Texas Eastern Transmission, LPa	BBB	Baa2	Not applicable
Westcoast Energy Inc.a	BBB	Not applicable	A(low)
Union Gas Limiteda	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLCb	A	A1	A
Maritimes & Northeast Pipeline, LPb	A	A1	A
Duke Energy Trading and Marketing, LLCc	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 Duke Energy’s capital and investment expenditures and dividends, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors affecting Duke Energy’s business, Duke Energy is unable to execute its business plan or if its earnings outlook materially deteriorates, Duke Energy’s ratings could be further affected.

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 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 March 31, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $370 million, compared to $510 million at December 31, 2003. The other potential collateral posting requirements as disclosed in Duke Energy’s Form 10-K for December 31, 2003 - Financing Cash Flows and Liquidity have not materially changed as of March 31, 2004. As a result the total potential collateral requirement including additional collateral, cash segregation and settlement payments declined from December 31, 2003.

Other Financing Matters.As of March 31, 2004, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $1,462 million in gross proceeds from debt and other securities. Subsequent to March 31, 2004, these SEC shelf registrations were increased by $988 million to provide future funding flexibility. As of March 31, 2004 there have been no changes under Canadian shelf registrations as disclosed in Duke Energy’s Form 10-K for December 31, 2003 – Financing Cash Flows and Liquidity.

43

Contractual Obligations and Commercial Commitments

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain 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” in Duke Energy’s Form 10-K for December 31, 2003, but note that in the chart for “Contractual Obligations as of December 31, 2003” under “Contractual Obligations and Commercial Commitments”, payments for “Energy commodity contracts” and “Total contractual cash obligations” should read as follows:

Contractual Obligations as of December 31, 2003 (in millions)
	Payments Due By Period
	Total		Less than 1 year (2004)		2-3 Years (2005 & 2006)		4-5 Years (2007 & 2008)		More than 5 Years (Beyond 2008)
Energy commodity contractsa	$	10,571	$	5,221	$	3,531	$	958	$	861
Total contractual cash obligations	$	54,390	$	9,515	$	13,347	$	5,828	$	25,700

^aIncludes contractual obligations to purchase physical quantities of power, natural gas and NGLs. Amount includes certain normal purchases, energy derivates and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2003. For certain of these amounts, Duke Energy may net settle rather than paying cash. Amount excludes contracts to purchase commodities that do not require delivery of physical quantities and also are expected to net settle.

CURRENT ISSUES

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

New Accounting Standards

The following new accounting standards have been issued by the authoritative accounting body, but have not yet been adopted or fully adopted by Duke Energy as of March 31, 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 postretirement plans, such as the following: (1) the long-term rate of return on plan assets along with narrative discussion of basis for selecting the rate of return used; (2) 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 by each major asset category and the actual allocation percentage at the measurement date; (3) 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; (4) current best estimate of range of contributions expected to be made in following year; (5) the accumulated benefit obligation for defined benefit pension plans; and (6) disclosure of measurement date utilized. Additionally, interim reports require certain additional disclosures related to the components of net periodic pension cost recognized and 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 postretirement plans as required by previous accounting standards. Except as discussed below, 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 March 31, 2004. The disclosure provisions of estimated future benefit payments will be effective for Duke Energy for the year ending December 31, 2004.

FASB Staff Position (FSP) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In January 2004, the FASB staff issued FSP FAS 106-1, which allows a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), which became law in December 2003. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. FSP FAS 106-1 allows a sponsor to defer recognizing the effects of the Act in accounting for its postretirement benefit plans under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” until further authoritative accounting guidance is issued. Duke Energy has a measurement date of September 30 for its SFAS No. 106 postretirement benefit plans and has elected to defer application of SFAS No. 106 to the provisions of the Act under the guidance given in FSP FAS 106-1. Therefore, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost contained in the Duke Energy Consolidated Financial Statements do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and such guidance, when issued, could require a change to previously reported information. Duke Energy is still reviewing the potential impacts of the Act on its postretirement benefit plans including whether the benefits under its plans are actuarially equivalent to Medicare Part D.

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

44

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 2004 and may require restatement of previously reported EPS measures if any changes to the calculation of EPS are required pursuant to the consensus. Duke Energy is currently assessing the impacts of this EITF Issue on its consolidated calculation of EPS.

Subsequent Events

As disclosed in Note 12 to the Consolidated Financial Statements, Subsequent Events, in Duke Energy’s Form 10-Q for June 30, 2003, Duke Energy announced the sale of a 25% undivided interest in the Duke Energy Vermillion facility. In May 2004, the sale of the 25% undivided interest in the Vermillion facility was completed for approximately $44 million. A loss on the sale of approximately $18 million was recorded in the third quarter of 2003. Duke Energy will continue to own the remaining 75% interest in the facility.

As disclosed in Note 23 to the Consolidated Financial Statements, Subsequent Events, in Duke Energy’s Form 10-K for December 31, 2003, DEFS announced that it had entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips. In May 2004, the acquisition of these assets was completed for approximately $74 million.

For information on subsequent events related to debt and credit facilities, see Note 5 to the Consolidated Financial Statements, Debt and Credit Facilities. For information related to the sale of International Energy’s Asia Pacific power generation and natural gas transmission businesses, and the sale of all of Duke Energy’s merchant generation assets in the Southeastern U.S., see Note 8 to the Consolidated Financial Statements, Assets Held for Sale and Discontinued Operations. For information related to the Enron bankruptcy, see Note 12 to the Consolidated Financial Statements, Commitments and Contingencies.

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 Form 10-K 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 $900 million as of March 31, 2004 and $700 million as of December 31, 2003. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $560 million as of March 31, 2004 and $400 million as of December 31, 2003, which are recorded on the Consolidated Balance Sheet in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. Duke Energy intends to fulfill these 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 utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures, 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.

45

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke 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)

	March 31, 2004 One-Day Impact on Operating Income for 2004(a)		Estimated Average One-   Day Impact on Operating Income for first quarter 2004(a)		Estimated Average One-   Day Impact on Operating Income for the year 2003(a)		High One-Day Impact on Operating Income for first quarter 2004(a)		Low One-Day Impact on Operating Income for first quarter 2004(a)
Calculated DER	$	28	$	25	$	8	$	47	$	11

^(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, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities”, is not material.

Equity Price Risk

As mentioned in the investing cash flows section of liquidity and capital resources, Duke Energy contributed cash in the second quarter of 2004 to a trust fund for certain costs of nuclear decommissioning. The 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.

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 Form 10-K, Duke Energy’s independent auditors, 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 American Institute of Certified Public Accountants. 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. Management continues to implement procedures and controls to address the identified deficiencies 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 first quarter of 2004 that have materially affected, or are reasonably likely to materially affect, Duke Energy’s internal control over financial reporting.

46

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For additional information concerning litigation and other contingencies, see Note 12 to the Consolidated Financial Statements, “Commitments and Contingencies;” and Item 3, “Legal Proceedings,” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” in Duke Energy’s Form 10-K for December 31, 2003, which are incorporated herein by reference.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).

Exhibit Number
10-18.1**	First Amendment to Employment Agreement dated March 9, 2004 between Paul M. Anderson and Duke Energy Corporation (filed with Form 10-K for the year ended December 31, 2003, as Exhibit 10-18.1).
10-20**	Separation Agreement and General Release dated January 30, 2004 between Duke Energy Corporation and Robert Brace (filed with Form 10-K for the year ended December 31, 2003, as Exhibit 10-20).
10-21**	Letter agreement dated January 28, 2004 between Duke Energy Corporation and Richard W. Blackburn (filed with Form 10-K for the year ended December 31, 2003, as Exhibit 10-21).
10-22**	Amendment and Supplement to Key Employee Severance Agreement and General Release dated as of February 2, 2004 between Duke Energy Corporation and Richard B. Priory (filed with Form 10-K for the year ended December 31, 2003, as Exhibit 10-22).
*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.

47

(b) Reports on Form 8-K

A Current Report on Form 8-K furnished on January 7, 2004 contained disclosures under Item 7, “Financial Statements and Exhibits,” and Item 12, “Results of Operations and Financial Condition.”

A Current Report on Form 8-K furnished on January 29, 2004 contained disclosures under Item 7, “Financial Statements and Exhibits,” and Item 12, “Results of Operations and Financial Condition.”

48

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: May 10, 2004	/s/    DAVID L. HAUSER
	David L. Hauser
	Group Vice President and
	Chief Financial Officer

Date: May 10, 2004	/s/    KEITH G. BUTLER
	Keith G. Butler
	Vice President and Controller

49