Duke Energy Carolinas 8-K Gains on sales of investments in commercial and multi-family real estate

Exhibit 99.2

Part I, Item 1. Financial Statements

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)

	Three Months Ended March 31,
	2005			2004
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	2,903		$	2,839
Regulated electric		1,258			1,266
Regulated natural gas and natural gas liquids		1,167			1,021
Total operating revenues		5,328			5,126
Operating Expenses
Natural gas and petroleum products purchased		2,750			2,591
Operation, maintenance and other		808			734
Fuel used in electric generation and purchased power		349			412
Depreciation and amortization		481			409
Property and other taxes		153			145
Impairment and other charges		121			—
Total operating expenses		4,662			4,291
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		42			59
Gains (Losses) on Sales of Other Assets, net		9			(339	)
Operating Income		717			555
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		41			34
Gains on sales and impairments of equity investments		1,239			—
Other income and expenses, net		24			32
Total other income and expenses		1,304			66
Interest Expense		290			343
Minority Interest Expense		420			40
Earnings From Continuing Operations Before Income Taxes		1,311			238
Income Tax Expense from Continuing Operations		451			76
Income From Continuing Operations		860			162
Discontinued Operations
Net operating loss, net of tax		(7	)		(91	)
Net gain on dispositions, net of tax		15			240
Income From Discontinued Operations		8			149
Net Income		868			311
Dividends and Premiums on Redemption of Preferred and Preference Stock		2			2
Earnings Available For Common Stockholders	$	866		$	309
Common Stock Data
Weighted-average shares outstanding
Basic		954			912
Diluted		990			947
Earnings per share (from continuing operations)
Basic	$	0.90		$	0.18
Diluted	$	0.87		$	0.17
Earnings per share (from discontinued operations)
Basic	$	0.01		$	0.16
Diluted	$	0.01		$	0.16
Earnings per share
Basic	$	0.91		$	0.34
Diluted	$	0.88		$	0.33
Dividends per share	$	0.275		$	0.275

See Notes to Consolidated Financial Statements for the Three Months Ended March 31, 2005 and 2004

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	March 31, 2005		December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,001	$	533
Short-term investments		1,064		1,319
Receivables (net of allowance for doubtful accounts of $154 at March 31, 2005 and $135 at December 31, 2004)		3,202		3,237
Inventory		747		942
Assets held for sale		21		40
Unrealized gains on mark-to-market and hedging transactions		1,246		962
Other		996		938
Total current assets		8,277		7,971
Investments and Other Assets
Investments in unconsolidated affiliates		1,282		1,292
Nuclear decommissioning trust funds		1,379		1,374
Goodwill		4,141		4,148
Notes receivable		171		232
Unrealized gains on mark-to-market and hedging transactions		1,532		1,379
Assets held for sale		41		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $16 at March 31, 2005 and $15 at December 31, 2004)		1,232		1,128
Other		1,954		1,896
Total investments and other assets		11,732		11,533
Property, Plant and Equipment
Cost		46,648		46,806
Less accumulated depreciation and amortization		13,257		13,300
Net property, plant and equipment		33,391		33,506
Regulatory Assets and Deferred Debits
Deferred debt expense		289		297
Regulatory assets related to income taxes		1,292		1,269
Other		927		894
Total regulatory assets and deferred debits		2,508		2,460
Total Assets	$	55,908	$	55,470

See Notes to Consolidated Financial Statements for the Three Months Ended March 31, 2005 and 2004

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	March 31, 2005		December 31, 2004
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	2,304	$	2,414
Notes payable and commercial paper		100		68
Taxes accrued		339		273
Interest accrued		273		287
Liabilities associated with assets held for sale		6		30
Current maturities of long-term debt		1,556		1,832
Unrealized losses on mark-to-market and hedging transactions		947		819
Other		1,596		1,815
Total current liabilities		7,121		7,538
Long-term Debt		16,934		16,932
Deferred Credits and Other Liabilities
Deferred income taxes		5,491		5,228
Investment tax credit		151		154
Unrealized losses on mark-to-market and hedging transactions		965		971
Liabilities associated with assets held for sale		14		14
Asset retirement obligations		1,974		1,926
Other		4,743		4,646
Total deferred credits and other liabilities		13,338		12,939
Commitments and Contingencies
Minority Interests		1,897		1,486
Preferred and Preference Stock without Sinking Fund Requirements		134		134
Common Stockholders’ Equity
Common stock, no par, 2 billion shares authorized; 928 million and 957 million shares outstanding at March 31, 2005 and December 31, 2004, respectively		10,436		11,252
Retained earnings		5,149		4,539
Accumulated other comprehensive income		899		650
Total common stockholders’ equity		16,484		16,441
Total Liabilities and Common Stockholders’ Equity	$	55,908	$	55,470

See Notes to the Consolidated Financial Statements for the Three Months Ended March 31, 2005 and 2004

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DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Three Months Ended March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	868		$	311
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		550			476
Gains on sales of investments in commercial and multi-family real estate		(42	)		(59	)
(Gains) losses on sales of equity investments and other assets		(1,272	)		80
Deferred income taxes		195			15
Minority interest		413			32
Purchased capacity levelization		(3	)		50
Contribution to company-sponsored pension plans		(13	)		(3	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		141			204
Receivables		59			305
Inventory		195			272
Other current assets		(91	)		(314	)
Increase (decrease) in
Accounts payable		(100	)		(400	)
Taxes accrued		107			280
Other current liabilities		(219	)		(199	)
Capital expenditures for residential real estate		(91	)		(46	)
Cost of residential real estate sold		38			21
Other, assets		(68	)		9
Other, liabilities		133			36
Net cash provided by operating activities		800			1,070
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures		(431	)		(592	)
Purchases of available-for-sale securities		(11,143	)		(7,807	)
Proceeds from sales and maturites of available-for-sale securities		11,352			7,706
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,322			183
Proceeds from the sales of commercial and multi-family real estate		51			167
Settlement of net investment hedges		(162	)		—
Other		—			17
Net cash provided by (used in) investing activities		989			(326	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		4			72
Issuance of common stock and common stock related to employee benefit plans		14			59
Payments for the redemption of:
Long-term debt		(419	)		(418	)
Notes payable and commercial paper		184			130
Distributions to minority interests		(195	)		(418	)
Contributions from minority interests		192			363
Dividends paid		(266	)		(265	)
Repurchase of common shares		(834	)		—
Other		—			1
Net cash used in financing activities		(1,320	)		(476	)
Changes in cash and cash equivalents associated with assets held for sale		(1	)		(31	)
Net increase in cash and cash equivalents		468			237
Cash and cash equivalents at beginning of period		533			397
Cash and cash equivalents at end of period	$	1,001		$	634

See Notes to Consolidated Financial Statements for the Three Months Ended March 31, 2005 and 2004

135

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2005 AND 2004

(Unaudited)

1. Basis of Presentation

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

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

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

Reclassifications and Other Changes.The accompanying Consolidated Statement of Cash Flows for the three months ended March 31, 2004 reflects a reclassification of instruments used in Duke Energy’s cash management program from cash and cash equivalents to short-term investments of $866 million and $763 million as of March 31, 2004 and December 31, 2003, respectively. This reclassification resulted in a $103 million decrease in the net increase in cash and cash equivalents on the Consolidated Statement of Cash Flows for the three months ended March 31, 2004. This reclassification was made in order to present certain auction rate securities and other highly-liquid instruments as short-term investments rather than as cash equivalents due to the stated tenor of the maturities of these investments.

Certain prior period amounts have been reclassified to conform to the presentation for the current period. Such reclassifications include the reclassification of the results of certain operations from continuing operations to discontinued operations (see Note 11). Except as required to reflect the effects of the Duke Energy North America (DENA) discontinued operations classification discussed in Note 11, the segment changes discussed in Note 12 and the Cinergy merger discussed in Note 19, the financial statements have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-Q for the quarter ended March 31, 2005. These changes impacted Note 2, Note 9, Note 11, Note 12 and Note 19.

2. Earnings Per Common Share (EPS)

Basic EPS is computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing earnings available for common stockholders, adjusted for the impact of dilutive securities to earnings, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock which have met market price or other contingencies (such as stock options, restricted, phantom and performance unit awards, convertible debt and derivative contracts indexed to common stock and settleable in cash or shares) were exercised, settled or converted into common stock.

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The following tables illustrate Duke Energy’s basic and diluted EPS calculations for income from continuing operations and reconcile the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three months ended March 31, 2005 and 2004.

(in millions, except per-share data)

	Income			Average Shares	EPS
Three Months Ended March 31, 2005
Income from continuing operations	$	860
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)
Income from continuing operations - basic	$	858		954	$	0.90
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock, and common stock derivatives				3
Contingently convertible bond		2		33
Income from continuing operations - diluted	$	860		990	$	0.87
Three Months Ended March 31, 2004
Income from continuing operations	$	162
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)
Income from continuing operations - basic	$	160		912	$	0.18
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		2		33
Income from continuing operations - diluted	$	162		947	$	0.17

The increase in weighted-average shares outstanding for the three months ended March 31, 2005 compared to the same period in 2004, was due primarily to the issuance of 41.1 million shares associated with the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004. Additionally, as discussed in Note 3, in March 2005, Duke Energy repurchased and retired 30 million shares of its common stock through an accelerated share repurchase transaction.

As a result of adopting the provisions of Emerging Issues Task Force (EITF) Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” as discussed in Note 17, Duke Energy has restated diluted earnings per share for the three months ended March 31, 2004 from $0.34 to $0.33.

Options, restricted stock, performance and phantom stock awards related to approximately 20 million shares as of March 31, 2005 and 25 million shares as of March 31, 2004 were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

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3. Common Stock

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. Total consideration paid to repurchase the shares of approximately $834 million, including approximately $10 million in commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock.

As part of the accelerated share repurchase transaction, Duke Energy simultaneously entered into a forward sale contract with the investment bank that matures no later than November 8, 2005. Under the terms of the forward sale contract, the investment bank will purchase, in the open market, 30 million shares of Duke Energy common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to Duke Energy. The timing of the purchase of the shares by the investment bank is dependent upon certain specified factors, including the market price of Duke Energy’s common stock. At settlement, Duke Energy, at its option, will either pay cash or issue registered or unregistered shares of its common stock to the investment bank if the investment bank’s weighted average purchase price is higher than the March 18, 2005 closing price of $27.46 per share, or the investment bank will pay Duke Energy either cash or shares of Duke Energy common stock, at Duke Energy’s option, if the investment bank’s weighted average price for the shares purchased is lower than the March 18, 2005 closing price of $27.46 per share. The amount of the payment will be the difference between the investment bank’s weighted average purchase price and $27.46 multiplied by the number of shares of Duke Energy common stock purchased by the investment bank.

The forward sale contract includes provisions that allow the investment bank to terminate earlier than November 8, 2005, if certain specified events occur. If such an early termination were to occur, Duke Energy would be required to issue registered or unregistered shares of its common stock, at Duke Energy’s option, sufficient for the investment bank to fulfill its obligation related to the 30 million shares sold to Duke Energy. The maximum number of shares of its common stock that Duke Energy could be required to issue to settle the forward sale contract is 60 million.

Duke Energy accounted for the forward sale contract under the provisions of EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock”, as an equity instrument. As the fair value of the forward sale contract at inception was zero, no accounting for the forward sale contract will be required, until settlement, as long as the forward sale contract continues to meet the requirements for classification as an equity instrument. Any amounts (cash or shares) either paid or received at settlement of the contract will be recorded in Common Stockholders’ Equity. At March 31, 2005, the investment bank had purchased 1,950,000 shares at a weighted average price of $27.84 per share. At April 30, 2005, the investment bank had purchased 6.6 million shares at a weighted average price of $28.25 per share.

Duke Energy also entered into a separate open market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. Duke Energy may terminate this plan at any time, without penalty. The timing of any repurchase of shares by the investment bank pursuant to this plan is dependent upon certain specified factors, including the market price of Duke Energy’s common stock. As of March 31, 2005, Duke Energy had not repurchased any shares of its common stock pursuant to this plan. At April 30, 2005, Duke Energy had repurchased 1.6 million shares of its common stock through this plan at a weighted average price of $28.80 per share. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment (see Note 19).

4. Stock-Based Compensation

Duke Energy accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and the Financial Accounting Standards Board (FASB) Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” The following table shows what earnings available for common stockholders, basic EPS and diluted EPS 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,” and provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment to FASB Statement No. 123)” to all stock-based compensation awards.

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

	Three Months Ended March 31,
	2005			2004
Earnings available for common stockholders, as reported	$	866		$	309
Add: stock-based compensation expense included in reported net income, net of related tax effects		7			3
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(7	)		(6	)
Pro forma earnings available for common stockholders, net of tax effects	$	866		$	306
EPS
Basic – as reported	$	0.91		$	0.34
Basic – pro forma	$	0.91		$	0.34
Diluted – as reported	$	0.88		$	0.33
Diluted – pro forma	$	0.88		$	0.33

5. Inventory

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

Inventory (in millions)

	March 31, 2005		December 31, 2004
Materials and supplies	$	449	$	445
Natural gas		111		312
Coal held for electric generation		118		104
Petroleum products		69		81
Total inventory	$	747	$	942

6. Debt and Credit Facilities

In December 2004, Duke Energy reached an agreement to sell its partially completed Grays Harbor power generation facility to an affiliate of Invenergy LLC (see Note 11). In 2004, Duke Energy also terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

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

During the three-month period ended March 31, 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

Available Credit Facilities and Restrictive Debt Covenants. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available 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 accelerated due dates and/or termination of the agreements. As of March 31, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

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Credit Facilities Summary as of March 31, 2005(in millions)

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
				Commercial Paper		Letters of Credit		Total
Duke Energy
$500 three-year syndicated (a), (b)	June 2007
$150 two-year bilateral (a), (b)	September 2005
Total Duke Energy		$	650	$	400	$	—	$	400
Duke Capital LLC
$600 364-day syndicated (a), (b), (c)	June 2005
$600 three-year syndicated (a), (b), (c)	June 2007
$130 three-year bi-lateral (b), (c)	October 2007
$120 multi-year bi-lateral (b), (c)	July 2009
Total Duke Capital LLC			1,450		—		837		837
Westcoast Energy Inc.
$165 three-year syndicated (b), (e)	June 2007
$83 two-year syndicated (b), (d)	July 2005
Total Westcoast Energy Inc.			248		—		—		—
Union Gas Limited
$248 364-day syndicated (f), (g)	June 2005		248		—		—		—
Duke Energy Field Services LLC
$250 364-day syndicated (c), (h), (i)	May 2005		250		—		—		—
Total (j)		$	2,846	$	400	$	837	$	1,237

(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) Credit facility is denominated in Canadian dollars, and was 100 million Canadian dollars as of March 31, 2005.

(e) Credit facility is denominated in Canadian dollars, and was 200 million Canadian dollars as of March 31, 2005.

(f) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars, and was 300 million Canadian dollars as of March 31, 2005.

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

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

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

(j) Various credit facilities that support ongoing operations and miscellaneous transactions are not included in this credit facilities summary.

On April 29, 2005, a new $450 million credit facility was established by Duke Energy Field Services, LLC (DEFS) with an expiration date of April 29, 2010. DEFS has the option at the expiration date to convert outstanding borrowings under the credit facility to an unsecured term loan with a final maturity date of April 29, 2011. This credit facility requires DEFS to maintain a debt-to-total capitalization ratio of less than or equal to 60% and an interest coverage ratio of at least 2.5 to 1.

7. Employee Benefit Obligations

The following table shows the components of the net periodic pension costs (income) for the Duke Energy U.S. retirement plan and Westcoast Energy, Inc. (Westcoast) Canadian retirement plans.

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

	Duke Energy U.S.						Westcoast
	2005			2004			2005			2004
Service cost	$	15		$	16		$	2		$	2
Interest cost on projected benefit obligation		39			40			7			6
Expected return on plan assets		(57	)		(58	)		(6	)		(6	)
Amortization of prior service cost		—			(1	)		—			—
Amortization of net transition asset		—			(1	)		—			—
Amortization of loss		9			4			1			1
Curtailment gain		—			(1	)		—			—
Net periodic pension costs (income)	$	6		$	(1	)	$	4		$	3

Duke Energy’s policy is to fund amounts for its U.S. retirement plan on an actuarial basis to provide assets sufficient to meet benefit payments to plan participants. Duke Energy has not made contributions to its U.S. retirement plan for the three month period ended March 31, 2005 and does not anticipate making a contribution to the U.S. retirement plan for the remainder of 2005.

Westcoast’s policy is to fund the defined benefit (DB) retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefit payments. Contributions to the defined contribution (DC) retirement plans are determined in accordance with the terms of the plans. Duke Energy has contributed $12 million to the Westcoast DB plans for the three month period ended March 31, 2005, and anticipates that it will make total contributions of approximately $38 million in 2005. Duke Energy has contributed $1 million to the Westcoast DC plans for the three month period ended March 31, 2005, and anticipates that it will make total contributions of approximately $3 million in 2005.

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

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

	Duke Energy U.S.						Westcoast
	2005			2004			2005		2004
Service cost benefit	$	1		$	1		$	1	$	1
Interest cost on accumulated post-retirement benefit obligation		11			14			1		1
Expected return on plan assets		(4	)		(5	)		—		—
Amortization of net transition liability		4			4			—		—
Amortization of loss		2			4			—		—
Net periodic post-retirement benefit costs	$	14		$	18		$	2	$	2

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy expensed employer matching contributions of $20 million for the three month period ended March 31, 2005 compared to $18 million for the three month period ended March 31, 2004.

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

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

Total Comprehensive Income(in millions)

	Three Months Ended March 31,
	2005		2004
Net Income	$	868	$	311
Other comprehensive income
Foreign currency translation adjustmentsa		47		(43	)
Net unrealized gains on cash flow hedgesb		143		127
Reclassification into earnings from cash flow hedgesc		59		6
Other comprehensive income, net of tax		249		90
Total Comprehensive Income	$	1,117	$	401

^a Foreign currency translation adjustments, net of $62 million tax benefit in 2005, related to the settled net investment hedges (see Note 13). This tax benefit is an immaterial correction of an accounting error related to prior periods.

^b Net unrealized gains on cash flow hedges, net of $74 million tax expense in 2005 and $52 million tax expense in 2004.

^c Reclassification into earnings from cash flow hedges, net of $30 million tax expense in 2005 and $3 million tax expense in 2004.

AOCI.The following table shows the components of and changes in AOCI.

Components of and Changes in AOCI(in millions)

	Foreign Currency Adjustments		Net Gains on Cash Flow Hedges		Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income
Balance as of December 31, 2004	$	540	$	526	$	(416	)	$	650
Other comprehensive income changes year-to-date (net of tax expense of $42)		47		202		—			249
Balance as of March 31, 2005	$	587	$	728	$	(416	)	$	899

9. Acquisitions and Dispositions

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

In the second quarter of 2004, Field Services acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. As the acquired assets were not considered businesses under the guidance in EITF Issue No. 98-3, no goodwill was recognized in connection with this transaction.

In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which DEFS owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Energy recognizing a pre-tax impairment of approximately $13 million, which was approximately $4 million net of minority interest. An additional 12% interest in

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Dauphin Island Gathering Partners (DIGP) was also purchased for $2 million, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

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

Dispositions.For the three months ended March 31, 2005, the sale of other assets and businesses resulted in approximately $1.2 billion in proceeds, net pre-tax gains of $9 million recorded in Gains (Losses) on Sales of Other Assets, net and pre-tax gains of $1.2 billion recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets held for sale as of March 31, 2005 and discontinued operations, both of which are discussed in Note 11, and sales by Crescent which are discussed separately below. Significant sales of other assets and equity investments during the three months ended March 31, 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which have been classified as Gains on Sales of Equity Investments in the Consolidated Statement of Operations for the three months ended March 31, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the three months ended March 31, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

Additionally, in February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. While the specifics of the transaction are still being negotiated, the consideration is expected to consist of the current Canadian operations of DEFS, the transfer of certain Canadian assets, or cash, from ConocoPhillips to Duke Energy, the transfer of cash from ConocoPhillips to DEFS, and the payment of cash from ConocoPhillips to Duke Energy of at least $500 million. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method after the transaction closes. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, has a target close date of June 30, 2005. See Note 13 for the impacts of this anticipated transaction on certain cash flow hedges. See also Note 12.

• Natural Gas Transmission asset sales totaled approximately $9 million in net proceeds. These sales resulted in pre-tax gains of approximately $2 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statement of Operations. These sales principally consisted of land tract sales.

• Additional asset and business sales totaled $5 million in net proceeds. These sales resulted in net pre-tax gains of $3 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations.

For the three months ended March 31, 2005, Crescent’s commercial and multi-family real estate sales resulted in $51 million of proceeds and $42 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales consisted of several large land tract sales.

In the first quarter of 2004, as a result of the marketing efforts related to DENA’s eight plants in the southeastern U.S., Duke Energy classified those assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million, which represented the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in Gains (Losses) on Sales of Other Assets, net in the first quarter 2004 Consolidated Statement of Operations. The fair value of the plants was based upon the anticipated price of approximately $475 million agreed upon with KGen Partners LLP (KGen) and announced on May 4, 2004. The sale closed in August 2004 and the actual sales price consisted of $420 million cash and a $48 million note receivable with principal and interest due no later than seven years and six months after the closing date. The entire balance of the note, including interest, was repaid by KGen in the first quarter of 2005. The agreement included the sale of all of Duke 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.

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In the first quarter of 2004, Duke Energy sold its 15% investment in Caribbean Nitrogen Company, an ammonia plant in Trinidad, and recognized a $13 million pre-tax gain, which was recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations.

10. Severance

During 2002, Duke Energy communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and will apply to individuals notified of layoffs between that date and January 1, 2006. As of March 31, 2005, no additional substantial charges are expected to be incurred under the plan. Provision for severance is included in Operations, Maintenance and Other in the Consolidated Statements of Operations.

Severance Reserve (in millions)	Balance at January 1, 2005		Provision/ Adjustments		Cash Reductions			Balance at March 31, 2005
International Energy	$	1	$	—	$	—		$	1
Field Services		—		1		—			1
Natural Gas Transmission		6		—		(1	)		5
Franchised Electric		4		—		(1	)		3
DENA		1		—		—			1
Other		3		—		—			3
Total (a)	$	15	$	1	$	(2	)	$	14

(a) Substantially all remaining severance payments are expected to be applied to the reserves within one year from the date that the provision was recorded.

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11. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations(in millions)

			Operating Income									Net Gain on Dispositions
	Operating Revenues		Pre-tax Operating Income			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain on Dispositions		Income Tax Expense		Gain on Dispositions, Net of Tax
Three Months Ended March 31, 2005
Field Services	$	4	$	—		$	—		$	—		$	—	$	—	$	—
DENA		491		(21	)		(13	)		(8	)		24		9		15
International Energy		—		2			1			1			—		—		—
Total consolidated	$	495	$	(19	)	$	(12	)	$	(7	)	$	24	$	9	$	15
Three Months EndedMarch 31, 2004
Field Services	$	36	$	2		$	1		$	1		$	2	$	1	$	1
DENA		602		(141	)		(43	)		(98	)		1		—		1
International Energy		65		5			(1	)		6			256		18		238
Total consolidated	$	703	$	(134	)	$	(43	)	$	(91	)	$	259	$	19	$	240

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

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

	March 31, 2005		December 31, 2004
Current assets	$	21	$	40
Investments and other assets		6		12
Property, plant and equipment, net		35		72
Total assets held for sale	$	62	$	124
Current liabilities	$	6	$	30
Long-term debt		14		14
Total liabilities associated with assets held for sale	$	20	$	44

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Field Services

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

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

In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third-party purchaser for a sales price of approximately $62 million, which approximated these assets’ carrying value. The results of operations related to these assets were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations for the three months ended March 31, 2004.

DENA

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets (see Note 19 for further details on the anticipated Cinergy merger). The exit plan is expected to be completed by the end of the third quarter of 2006. In addition, management will continue to wind down the limited remaining operations of DETM. The DENA assets to be divested include:

• Approximately 6,200 megawatts of power generation located primarily in the western and eastern United States, including the Ft. Frances generation facility in Ontario, Canada and all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

• All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

• Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

The results of operations of DENA’s western and eastern United States generation assets, including related commodity contracts, the Ft. Frances generation assets, substantially all of the contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, qualify for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations.

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, DENA’s Southeastern generation operations, including related commodity contracts do not qualify for discontinued operations classification due to Duke Energy’s continuing involvement with these operations (see also Note 9). In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

See Note 12 for a discussion of the impacts of this exit activity on Duke Energy’s segment presentation.

In the first quarter of 2005, DENA sold the partially completed Grays Harbor facility to an affiliate of Invenergy LLC. The resulting proceeds and tax benefits for this transaction, excluding any potential contingent consideration, was approximately $116 million. A pre-tax gain of approximately $21 million was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations in 2005. The termination of the capital lease substantially offsets the proceeds and tax benefits from the sale. See also Note 6.

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On September 21, 2004, DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving will purchase DENA’s 75% interest in Bayside Power L.P. (Bayside). Closing will occur upon receipt of required third-party consents and regulatory approvals which are expected sometime in the second quarter 2005. As a result of the above agreement, DENA presented the $62 million of assets and $20 million of liabilities related to Bayside as Assets Held For Sale in the Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was $20 million at March 31, 2005 and $19 million at December 31, 2004. Bayside was consolidated with the adoption of FASB Interpretation (FIN) No. 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51”, on March 31, 2004. Therefore, Bayside’s operating results after March 31, 2004 are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.

International Energy

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

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

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12. Business Segments

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

The remainder of Duke Energy’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes DENA’s continuing operations (beginning in 2005, as discussed further below), certain unallocated corporate costs, certain discontinued hedges, DukeNet Communications, LLC, Duke Energy Merchants, LLC (DEM), Bison Insurance Company (Bison), Duke Energy’s wholly owned, captive insurance subsidiary and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD).

As discussed further in Note 11, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended March 31, 2005 increased Other’s segment losses by approximately $30 million. Additionally, in connection with this exit plan, DENA transferred its 50% equity investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Energy’s Natural Gas Transmission segment. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

During the first quarter of 2005, Duke Energy recognized a charge to increase liabilities associated with mutual insurance companies of $28 million in Other, which was an immaterial correction of an accounting error related to prior periods.

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 Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).

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

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

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Business Segment Data(in millions)

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
Three Months Ended March 31, 2005
Franchised Electric	$	1,260	$	5		$	1,265		$	336
Natural Gas Transmission		1,155		36			1,191			411
Field Services		2,575		83			2,658			918
International Energy		168		—			168			68
Crescent		64		—			64			52
Total reportable segments		5,222		124			5,346			1,785
Othera		106		(59	)		47			(202	)
Eliminations		—		(65	)		(65	)		—
Interest expense		—		—			—			(290	)
Interest income and otherb		—		—			—			18
Total consolidated	$	5,328	$	—		$	5,328		$	1,311
Three Months Ended March 31, 2004
Franchised Electric	$	1,266	$	5		$	1,271		$	424
Natural Gas Transmission		1,012		41			1,053			402
Field Services		2,352		(13	)		2,339			88
DENAa		5		12			17			(430	)
International Energy		154		—			154			29
Crescent		38		—			38			60
Total reportable segments		4,827		45			4,872			573
Other		299		45			344			(5	)
Eliminations		—		(90	)		(90	)		—
Interest expense		—		—			—			(343	)
Interest income and otherb		—		—			—			13
Total consolidated	$	5,126	$	—		$	5,126		$	238

^a Other includes DENA’s continuing operations for 2005. DENA segment data includes continuing operations for DENA in periods prior to 2005.

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

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

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Segment Assets(in millions)

	March 31, 2005			December 31, 2004
Franchised Electric	$	18,133		$	18,199
Natural Gas Transmission		17,553			17,498
Field Services		7,104			6,436
DENA a		5,210			6,719
International Energy		3,407			3,329
Crescent		1,410			1,315
Total reportable segments		52,817			53,496
Other		3,399			1,829
Reclassifications and eliminationsb		(308	)		145
Total consolidated assets	$	55,908		$	55,470

^a DENA’s segment assets include the assets for DENA’s discontinued operations as of March 31, 2005 (see Note 11).

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

Segment assets include goodwill of $4,141 million as of March 31, 2005 and $4,148 million as of December 31, 2004, with $3,404 million allocated to Natural Gas Transmission, $480 million to Field Services, $250 million to International Energy and $7 million to Crescent as of March 31, 2005. The $7 million decrease from December 31, 2004 to March 31, 2005 was related solely to foreign currency exchange rate fluctuations of $11 million at Natural Gas Transmission, partially offset by an increase of $4 million at International Energy.

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13. Risk Management Instruments

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

Derivative Portfolio Carrying Value(in millions)

	March 31, 2005			December 31, 2004
Hedging	$	1,234		$	801
Trading		23			54
Undesignated		(391	)		(304	)
Total	$	866		$	551

The amounts in the table above represent the combination of assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Energy’s Consolidated Balance Sheets. All amounts represent current fair value, except that the net asset amounts for hedging include assets of $119 million as of March 31, 2005 and $160 million as of December 31, 2004, that were frozen upon Duke Energy’s initial application of the normal purchases and normal sales exception to its forward power sales contracts as of July 1, 2001. These asset values will amortize as they settle over approximately five years.

The $433 million increase in the hedging derivative portfolio carrying value is due primarily to increases in forward natural gas prices, partially offset by the realization of natural gas hedge gains as well as other hedge activity.

The $87 million decrease in the undesignated derivative portfolio fair value is due primarily to mark-to-market of certain contracts held by Duke Energy related to Field Services’ commodity price risk. As a result of the anticipated transfer of 19.7% interest in DEFS to ConocoPhillips and the deconsolidation of its investment in DEFS (see Note 9), Duke Energy has discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. As a result, approximately $120 million of unrealized pre-tax losses previously recorded in AOCI related to these contracts has been recognized in earnings by Duke Energy in the three months ended March 31, 2005. These charges have been classified as a component of Impairment and Other Charges in the Consolidated Statement of Operations. Since discontinuance of hedge accounting, these contracts have been marked-to market in the Consolidated Statement of Operations, resulting in the recognition of approximately $110 million of additional unrealized pre-tax losses, classified as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other Revenues in the Consolidated Statement of Operations for the three months ended March 31, 2005. The decrease in the undesignated derivative portfolio fair value is partially offset by certain contract terminations at DENA.

Included in Other Current Assets in the Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004 are collateral assets of approximately $501 million and $300 million, respectively, which represents cash collateral posted by Duke Energy with other third parties. Included in Other Current Liabilities in the Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004 are collateral liabilities of approximately $516 million and $481 million, respectively, which represents cash collateral posted by other third parties to Duke Energy.

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

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

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As of March 31, 2005, $470 million of the pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

The ineffective portion of commodity cash flow hedges resulted in the recognition of a loss of approximately $25 million in the three months ended March 31, 2005 as compared to a gain of $2 million in the three months ended March 31, 2004.

See Note 19 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

14. Regulatory Matters

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 Federal Energy Regulatory Commission (FERC) approves Franchised Electric’s rates for electric sales to regulated wholesale customers.

In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). Franchised Electric’s amortization expense related to this clean air legislation totals $412 million from inception, with $85 million recorded for the first quarter 2005 and $16 million recorded for the first quarter 2004. As of March 31, 2005, cumulative expenditures totaled $190 million, with $63 million incurred in the first quarter 2005 and $11 million incurred in the first quarter 2004, and are included in Net Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows. Based upon current estimates on file with the NCUC, Franchised Electric estimates total cost of complying with the clean air legislation to be approximately $1.7 billion, which is an increase from previous estimates of approximately $1.5 billion. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period.

Depreciation and Decommissioning Studies. In March 2005, Duke Power Company (Duke Power) filed the results of a depreciation rate study with the NCUC and PSCSC. Duke Power has adopted new depreciation rates for all functions retroactively, effective January 1, 2005. The application of the new rates to depreciable plant in service as of January 1, 2005 is expected to result in an immaterial change in depreciation expense in 2005.

In June 2004, Duke Power filed with the NCUC and PSCSC the results of a 2003 nuclear decommissioning study, which indicate an estimated cost of $2.3 billion (in 2003 dollars) to decommission the nuclear facilities. The previous study, conducted in 1999, estimated a decommissioning cost of $1.9 billion ($2.2 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning).

In October 2004, Duke Power filed the results of a funding study for nuclear decommissioning costs with the NCUC and in December 2004, Duke Power notified the PSCSC of the results of the funding study.

Over-Accrued Deferred Taxes. On March 9, 2005, Duke Power filed with the NCUC a proposed fuel rate increase, for rates effective July 1, 2005 for a 12-month period. To reduce the impact of the increased cost of fuel, Duke Power is seeking approval in the fuel case proceeding to credit the deferred fuel account by approximately $100 million for previously recorded excess deferred tax liabilities that are recorded as regulatory liabilities. The filing has not yet been approved. No similar action has yet been proposed to the PSCSC.

Natural Gas Transmission.Rate Related Information. In April 2005, The British Columbia Pipeline System (BC Pipeline) received National Energy Board (NEB) approval of final 2005 tolls in accordance with its 2004/2005 toll settlement agreement.

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In December 2004, the Ontario Energy Board (OEB) approved the 2005 rates for Union Gas Limited (Union Gas). The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the 9.63% benchmark return on equity (ROE), normalized for weather, will be shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below the allowed ROE, normalized for weather. In March 2005, the OEB dismissed an appeal by Union Gas for reconsideration of the December decision. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $8 million during the three months ended March 31, 2005.

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

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In April 2005, an agreement in principle was reached with customers that would provide for a rate increase. The FERC schedule has been suspended for 30 days to allow the parties to finalize settlement documents. This agreement, once finalized, is expected to be filed with FERC for its review and approval in the second quarter of 2005.

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

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

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

Clean Water Act. The Environmental Protection Agency’s final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina and its three natural

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

North Carolina Clean Air Legislation. As discussed in Note 14, in 2002 the state of North Carolina passed clean air legislation in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of SO2 and NOx from coal-fired power plants in the state.

Clean Air Mercury Rule. In March 2005, the U.S. Environmental Protection Agency’s (EPA) acting administrator signed the final Clean Air Mercury Rule (CAMR). The rule limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. Phase 1 begins in 2010 and Phase 2 begins in 2018. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAMR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAMR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position and is currently unable to estimate the cost of complying with Phase 2 of the CAMR.

Clean Air Interstate Rule. In March 2005, the EPA’s acting administrator signed the final Clean Air Interstate Rule (CAIR). The rule limits total annual SO2 and NOx emissions from electric generating facilities across the eastern United States through a two-phased cap-and-trade program. Phase 1 begins in 2009 for NOx and 2010 for SO2. Phase 2 begins in 2015 for both NOx and SO2. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAIR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position and is currently unable to estimate the cost of complying with Phase 2 of the CAIR.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were accruals related to extended environmental-related activities of approximately $70 million as of March 31, 2005. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s 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 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 when it undertook those projects without obtaining permits and installing emission controls for SO2, NOx 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. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy’s legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy. The government has appealed the case to the U.S. Fourth Circuit Court of Appeals. The Fourth Circuit heard oral argument on February 3, 2005. A decision is pending. Based on the current rulings by the trial court, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position. Subsequent rulings by the appellate court could significantly affect the outcome.

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Western Energy Litigation. Since 2000, plaintiffs have filed 47 lawsuits in four western states against Duke Energy affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Eleven suits have been dismissed on filed rate and/or federal preemption grounds. The plaintiffs in 10 of the dismissed suits have appealed or filed notice of appeal, and the U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit has petitioned the U.S. Supreme Court for certiorari and that court has invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted.

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

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

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint Venture with ExxonMobil Corporation) relating to amounts owed in connection with the termination of bilateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in excess of $90 million. Based on the level of damages claimed by the plaintiff and Duke Energy’s assessment of possible outcomes in this matter, Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

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

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

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reactivated demand as well as matters that were the subject of the California Settlement. On March 16, 2005, the special committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims.

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

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

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

In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Energy recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the three indicted former DETMI employees pled guilty to a books and records violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls.

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

In February 2005, the Commodity Futures Trading Commission initiated a civil action against a former DETM trader asserting charges of delivering false reports and attempted manipulation of prices through index price reporting. Duke Energy is not named in this action.

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

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

ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. ExxonMobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that ExxonMobil breached its Ventures obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of ExxonMobil’s claims. Duke Energy continues to evaluate the impact of this order on the pending arbitration. A hearing in this arbitration has been tentatively scheduled for January 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain ExxonMobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Ventures and wrongfully failed to assume certain related gas supply agreement with other parties. A hearing in the Canadian arbitration proceeding has been scheduled to begin in August 2005 in Calgary, Canada. It is not possible to predict with certainty the damages that might be incurred by Duke Energy or any of its affiliates as a result of these matters.

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. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within noncurrent assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

Duke Energy has exposure to certain legal matters that are described herein. As of March 31, 2005, Duke Energy has recorded reserves of approximately $1.4 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of March 31, 2005, Duke Energy has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

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

16. Guarantees and Indemnifications

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

Mixed Oxide (MOX) Guarantees.Duke COGEMA Stone & Webster, LLC (DCS) is the prime contractor to the U.S. Department of Energy (DOE) under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of March 31, 2005, Duke Energy, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

The Prime Contract consists of a “Base Contract” phase and successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of March 31, 2005, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Energy estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of March 31, 2005, Duke Energy had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.

In connection with the Prime Contract, Duke Energy, through its Duke Power franchised electric business, has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of March 31, 2005, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.

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

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

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

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

Other Guarantees and Indemnifications.Duke Capital LLC (Duke Capital), a wholly-owned subsidiary of Duke Energy, 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, 2005 was approximately $800 million. Of this amount, approximately $450 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $50 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2008 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of March 31, 2005 was approximately $60 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of March 31, 2005 was approximately $525 million. Of this amount, approximately $500 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities. Substantially all of these letters of credit expire in 2005.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of March 31, 2005, Duke Capital had guaranteed approximately $15 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2005 and 2006. Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As

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of March 31, 2005, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly-owned entities, with substantially all of the guarantees expiring in 2005.

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

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

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

As of March 31, 2005, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

17. New Accounting Standards

The following new accounting standards were adopted by Duke Energy subsequent to March 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

FASB Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In May 2004, the FASB staff issued FSP No. FAS 106-2, which superseded FSP No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP No. FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Post-retirement

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Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $12 million for both 2004 and 2005.

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

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

EITF Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share.” In September 2004, the EITF reached a consensus on Issue No. 04-8. The consensus in Issue No. 04-8 requires that the potential common stock related to contingently convertible securities (Co-Cos) with market price contingencies be included in diluted earnings per share calculations using the if-converted method specified in SFAS No. 128, “Earnings per Share,” whether the market price contingencies have been met or not. Co-Cos generally require conversion into a company’s common stock if certain specified events occur, such as a specified market price for the company’s common stock. Prior to the issuance of EITF Issue No. 04-8, Co-Cos were treated as contingently issuable shares under SFAS No. 128, and therefore, the contingencies, must have been met in order for the potential common shares to be included in diluted EPS. Therefore, Co-Cos were only included in diluted earnings per share during periods in which the contingencies had been met. The consensus in Issue No. 04-8 was effective for fiscal years ended after December 15, 2004 and has been applied retroactively to all periods in which any Co-Cos were outstanding, resulting in restatement of diluted earnings per share if the impact of the Co-Cos was dilutive.

As discussed in Note 15, “Debt and Credit Facilities”, to Duke Energy’s Form 10-K for the year ended December 31, 2004, Duke Energy issued $770 million par value of contingently convertible notes in May of 2003, bearing an interest rate of 1.75% per annum that contain several contingencies, including a market price contingency that, if met, may require conversion of the notes into Duke Energy common stock. Conversion may be required, at the option of the holder, if any one of the contingencies is met. Therefore, as discussed in Note 2, Duke Energy has included potential common shares of approximately 33 million in the calculation of diluted EPS for the periods in which the $770 million contingently convertible notes have been outstanding and for which the impact of conversion was dilutive.

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus in Issue No. 03-13 also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the

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

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of March 31, 2005:

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

The impact on EPS for the three-month periods ended March 31, 2005 and 2004 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed in the Pro Forma Stock-Based Compensation table included in Note 4. Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Energy does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new equity-based compensation awards issued to employees.

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

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 29’s concept of culmination of an earning process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. SFAS No. 153 does not apply to transfers of nonmonetary assets between entities under common control. The impact to Duke Energy of adopting SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Energy does not currently expect adoption of SFAS No. 153 will have a material impact on its consolidated results of operations, cash flows or financial position.

FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations”. In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. Duke Energy is currently evaluating the impact of adopting FIN 47 as well as the interim transition provisions and cannot currently estimate the impact of FIN 47 on its consolidated results of operations, cash flows or financial position.

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18. Income Tax Expense

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

Under the guidance in FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. In the first quarter of 2005, Duke Energy recognized a benefit of approximately $2 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Energy plans to repatriate approximately $500 million in extraordinary dividends in 2005, as defined in the Act, and accordingly recorded a corresponding tax liability of $45 million as of December 31, 2004.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income and other taxes have been made for potential liabilities resulting from such matters. As of March 31, 2005, Duke Energy has total provisions for uncertain tax positions of approximately $145 million as compared to $149 million as of December 31, 2004, which includes interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

19. Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-Q for the quarter ended March 31, 2005, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

Acquisitions and Dispositions - Field Services . In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP) for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion and Minority Interest Expense of $343 million to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. During 2005, Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $.8 billion in cash and approximately $.3 billion of assets. The DEFS disposition resulted in pre-tax gain of approximately $575 million in third quarter 2005. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. In connection with the DEFS disposition, Duke Energy acquired ConocoPhillips interest in the Empress System gas processing and natural gas liquids marketing business (Empress System) in August 2005 for cash of approximately $230 million.

Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment.

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The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see also Note 9 to the Consolidated Financial Statements).

As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market. As a result, approximately $355 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy in the nine months ended September 30, 2005. Upon the discontinuance of hedge accounting, approximately $120 million of pre-tax charges were recognized while approximately $235 million of losses have been recognized subsequent to discontinuance of hedge accounting.

Acquisitions and Dispositions - DENA.As described in Note 11 to the Consolidated Financial Statements, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

• The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)

• The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan, and

• Pre-tax impairments of approximately $0.6 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon information from third party valuations and internal valuations.

In addition to these amounts, at September 30, 2005, approximately $150 million of pre-tax deferred net gains remain in AOCI related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings over the next 12 months as the forecasted transactions occur. In addition, management anticipates that additional charges will be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts estimated at approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs. The actual amount of future additional charges related to the DENA exit plan will vary depending on changes in market conditions and other factors, and could differ from management’s current expectation.

DENA may also realize future potential gains on sales of certain plants which will be recognized when sold. Subsequent to September 30, 2005, DENA has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. Included in the estimated exit costs are the effects of DENA’s November 17, 2005 agreement to sell to Barclays Bank PLC (Barclays) substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and contracts related to DENA’s energy marketing and management activities. Excluded from the sale to Barclays are commodity contracts associated with the near-term value of DENA’s west and northeastern generation assets and with remaining gas transportation and structured power contracts. Among other things, the agreement provides that effective November 17, 2005 all economic benefits and burdens under the contracts were transferred to Barclays. DENA agreed to pay Barclays cash consideration of approximately $700 million by January 3, 2006 and as the contracts are novated, assigned or terminated, all net collateral posted by DENA under those contracts will be returned to DENA. Net cash collateral to be returned to DENA is expected to substantially offset the cash consideration to be paid to Barclays. The novation or assignment of physical power contracts is subject to Federal Energy Regulatory Commission approval.

As of September 30, 2005, DENA’s assets and liabilities to be disposed of under the exit plan, were classified as Assets Held for Sale and consisted of the following:

Summarized DENA Assets and Associated Liabilities Held for Sale As of September 30, 2005 (in millions)

Current assets	$	1,579
Investments and other assets		1,556
Net property, plant and equipment		1,151
Total assets held for sale	$	4,286
Current liabilities	$	1,605
Long-term debt and other deferred credits		2,260
Total liabilities associated with assets held for sale	$	3,865

In October 2005, the Ft. Frances generation facility was sold to a third party for proceeds which approximate the carrying value of the sold assets.

Acquisitions and Dispositions - Cinergy Merger.On May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common

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share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at September 30, 2005, the holding company would issue approximately 310 million shares to convert the Cinergy common shares. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, had the transaction closed as of September 30, 2005, it would have been valued approximately as follows:

Pro forma Cinergy Merger Transaction Value

	(in millions)
Value of common stock and other consideration provided	$	9 billion
Fair value of net assets acquired		5 billion
Incremental goodwill from Cinergy acquisition	$	4 billion

The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including approval of shareholders of both companies and a number of federal and state governmental authorities. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

Additionally, Duke Energy has announced plans to suspend additional repurchases under its open market share purchase plan pending further assessment, as discussed in Note 3.

Acquisitions and Dispositions – Natural Gas Transmission: In April 2005, Natural Gas Transmission agreed to acquire natural gas storage and pipeline assets in southwest Virginia and a 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. Upon closing of this transaction, which is estimated to be in the third quarter of 2005, Natural Gas Transmission will own 100% of Saltville Storage.

For information on subsequent events related to common stock, debt and credit facilities, regulatory matters, and litigation see Notes 3, 6, 14 and 15.

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

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the Three Months Ended March 31, 2005 and 2004.

Overview of Business Strategy and Economic Factors

Duke Energy Corporation’s (collectively with its subsidiaries, Duke Energy’s) business strategy is to create value for customers, employees, communities and shareholders through the production, conversion, delivery and sale of energy and energy services. Duke Energy’s plan is to emphasize income for its shareholders, with modest growth. For an in-depth discussion of Duke Energy’s business strategy and economic factors, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004.

As discussed in Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of Duke Energy North America’s (DENA) remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy Corp. (Cinergy) provides a sustainable business model for those assets. The exit plan is expected to be completed by the end of the third quarter of 2006.

RESULTS OF OPERATIONS

Results of Operations and Variances(in millions)

	Three Months Ended March 31,
	2005		2004			Increase (Decrease)
Operating revenues	$	5,328	$	5,126		$	202
Operating expenses		4,662		4,291			371
Gains on sales of investments in commercial and multi-family real estate		42		59			(17	)
Gains (losses) on sales of other assets, net		9		(339	)		348
Operating income		717		555			162
Other income and expenses, net		1,304		66			1,238
Interest expense		290		343			(53	)
Minority interest expense		420		40			380
Earnings from continuing operations before income taxes		1,311		238			1,073
Income tax expense from continuing operations		451		76			375
Income from continuing operations		860		162			698
Income from discontinued operations, net of tax		8		149			(141	)
Net income		868		311			557
Dividends and premiums on redemption of preferred and preference stock		2		2			—
Earnings available for common stockholders	$	866	$	309		$	557

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Overview of Drivers and Variances

Three Months Ended March 31, 2005 as Compared to March 31, 2004.For the three months ended March 31, 2005, earnings available for common stockholders were $866 million, or $0.91 per basic share and $0.88 per diluted share. For the three months ended March 31, 2004, earnings available for common stockholders were $309 million, or $0.34 per basic share and $0.33 per diluted share. Significant items that contributed to increased earnings available for common stockholders for the quarter included:

• A $1,142 million pre-tax gain ($799 million net of minority interest of $343 million) recorded in 2005 on the sale of Duke Energy Field Services, LLC’s (DEFS) wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, L.P. (TEPPCO LP), an equity method investment of DEFS

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

• A $97 million pre-tax gain recorded in 2005 on the sale of Duke Energy’s limited partner interest in TEPPCO LP

• An approximate $85 million pre-tax increase in earnings ($60 million net of minority interest of $25 million) at Field Services due primarily to the favorable effects of commodity prices, net of hedging, and

• A $53 million pre-tax decrease in interest expense, due primarily to Duke Energy’s lower debt balance in 2005.

Partially offsetting these increases and prior-year charges were:

• A $380 million increase in minority interest expense, due primarily to the gain associated with the sale of TEPPCO GP, discussed above

• A $375 million increase in income tax expense from continuing operations, resulting primarily from higher earnings, primarily the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above

• An approximate $230 million of unrealized pre-tax losses recognized in 2005 on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”)

• A $141 million decrease from discontinued operations due primarily to a $238 million after-tax gain recognized in discontinued operations in 2004 related to the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business), partially offset by a $104 million after-tax favorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified as discontinued operations as a result of the DENA exit plan (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), and

• A $28 million mutual insurance liability adjustment related to Bison Insurance Company Limited (Bison) which was an immaterial correction of an accounting error related to prior periods.

On a consolidated and a segment reporting basis, results of operations through March 31, 2005, may not be indicative of the full year.

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Consolidated Operating Revenues

Three Months Ended March 31, 2005 as Compared to March 31, 2004.Consolidated operating revenues for the three months ended March 31, 2005 increased $202 million, compared to the same period in 2004. This change was driven primarily by:

• A $319 million increase at Field Services due primarily to higher average commodity prices, primarily natural gas liquids (NGL) and natural gas, in 2005

• A $138 million increase at Natural Gas Transmission due primarily to higher natural gas prices that are passed through to customers and favorable foreign exchange rates as a result of the strengthening Canadian dollar (mostly offset by gas price and currency impacts to expenses), and

• An approximate $50 million increase due principally to higher residential developed lot sales at Crescent and higher energy prices at International Energy.

Partially offsetting these increases in revenues were:

• A $196 million decrease in revenue as a result of the continued wind-down of Duke Energy Merchants LLC (DEM), and

• An approximate $110 million decrease resulting from unrealized mark-to-market losses due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”).

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

Consolidated Operating Expenses

Three Months Ended March 31, 2005 as Compared to March 31, 2004.Consolidated operating expenses for the three months ended March 31, 2005 increased $371 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $400 million increase in operating expenses at Field Services and Natural Gas Transmission driven primarily by higher average NGL and natural gas prices, and foreign exchange impacts

• An approximate $120 million increase related to the recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”), and

• An $80 million increase in operating expenses at Franchised Electric due primarily to increased planned outage and maintenance costs at fossil and nuclear generating plants and increased regulatory amortization.

Partially offsetting these increases in expenses were:

• A $201 million decrease due to the continued wind-down of DEM, and

• A $59 million decrease in operating costs from DENA’s continuing operations, due primarily to the sale of the Southeast Plants in 2004 and the continued wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with ExxonMobil Corporation).

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

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

Consolidated gains (losses) on sales of other assets, net for the three months ended March 31, 2005 increased $348 million, compared to the same period in 2004. The increase was due primarily to the approximately $360 million pre-tax charge in 2004 associated with the sale of DENA’s Southeast Plants.

Consolidated Operating Income

Consolidated operating income for the three months ended March 31, 2005 increased $162 million, compared to the same period in 2004. Increased operating income was primarily driven by the change in consolidated gains (losses) on sales of other assets, net of approximately $350, as discussed above and an approximate $85 million increase at Field Services due primarily to the favorable effects of commodity prices, partially offset by the approximate $230 million negative impact to operating income related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, as discussed above. Other drivers to operating income are discussed above.

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

Consolidated Other Income and Expenses, net

Consolidated other income and expenses, net for the three months ended March 31, 2005 increased $1,238 million, compared to the same period in 2004. The increase was due primarily to the $1,239 million pre-tax gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above.

Consolidated Interest Expense

Consolidated interest expense for the three months ended March 31, 2005 decreased $53 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s lower debt balance in 2005.

Consolidated Minority Interest Expense

Consolidated minority interest expense for the three months ended March 31, 2005 increased $380 million, compared to the same period in 2004. The increase primarily resulted from the gain associated with the sale of TEPPCO GP as discussed above.

Consolidated Income Tax Expense from Continuing Operations

Consolidated income tax expense from continuing operations for the three months ended March 31, 2005 increased $375 million, compared to the same period in 2004. The increase primarily resulted from higher earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above.

Consolidated Income from Discontinued Operations, net of income tax

Consolidated income from discontinued operations, net of income tax for the three months ended March 31, 2005 decreased $141 million, compared to the same period in 2004. The decrease primarily resulted from a $238 million after-tax gain recorded in 2004 on sale of International Energy’s Asia-Pacific Business, partially offset by a $104 million after-tax favorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified to discontinued operations as a result of the DENA exit plan (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Segment Results

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement,

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and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.

As discussed in Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA’s segment. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 9 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

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

EBIT by Business Segment(in millions)

	Three Months Ended March 31,
	2005			2004
Franchised Electric	$	336		$	424
Natural Gas Transmission		411			402
Field Services		918			88
DENAa		—			(430	)
International Energy		68			29
Crescent		52			60
Total reportable segment EBIT		1,785			573
Othera		(202	)		(5	)
Interest expense		(290	)		(343	)
Interest income and otherb		18			13
Consolidated earnings from continuing operations before income taxes	$	1,311		$	238

^a Other includes DENA’s continuing operations for 2005. DENA segment data includes continuing operations for DENA for periods prior to 2005.

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

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

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Franchised Electric

	Three Months Ended March 31,
(in millions, except where noted)	2005		2004		Increase (Decrease)
Operating revenues	$	1,265	$	1,271	$	(6	)
Operating expenses		931		851		80
Gains on sales of other assets, net		1		—		1
Operating income		335		420		(85	)
Other income, net of expenses		1		4		(3	)
EBIT	$	336	$	424	$	(88	)
Sales, Gigawatt-hours (GWh)		21,163		21,963		(800	)

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

Increase (decrease) over prior year	Three Months Ended March 31, 2005
Residential salesa	(1.5	)%
General service salesa	1.6	%
Industrial salesa	5.9	%
Wholesale sales	(25.8	)%
Total Franchised Electric sales	(3.6	)%
Average number of customers	2.0	%

^a Major components of Franchised Electric’s retail sales.

Three Months Ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues.The decrease was driven primarily by:

• A $19 million decrease in GWh sales to retail customers due to milder winter weather during the quarter

• A $10 million decrease due to sharing of profits from wholesale power sales with customers in North Carolina in 2005 through a rate reduction. Sharing of profits did not begin until the second quarter of 2004

• Wholesale GWh sales declined by approximately 26% in 2005 as compared to 2004 due to mild weather, an increase in planned generation outages and transmission constraints related to an outage in Tennessee in 2005. The decrease in GWh sales were principally offset by an increase in wholesale prices during the quarter.

These decreases were partially offset by

• An $11 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory. The number of customers in 2005 has increased by approximately 45,000 compared to the same period in 2004, and

• An $8 million increase in billed and unbilled fuel revenues driven by increased fuel rates for retail customers, due primarily to increased coal costs. The delivered cost of coal in 2005 is approximately $7 per ton higher than the same period in 2004 and this increase will be reflected in both billed and unbilled fuel revenue.

Operating Expenses.The increase was driven primarily by:

• Increased operating and maintenance expenses of $31 million, due primarily to increased planned outage and maintenance costs at fossil and nuclear generating plants. The number of outages and maintenance projects scheduled at fossil plants increased during the period, with five baseload outages in 2005 compared to three in 2004. Labor costs, planned maintenance on plant equipment and charges related to offsite backup power increased at nuclear stations

• Increased regulatory amortization of approximately $16 million, due primarily to increased amortization of compliance costs related to clean air legislation passed by the state of North Carolina. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized,

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within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized by December 31, 2007. Regulatory amortization expenses in 2005 were approximately $85 million as compared to approximately $69 million during the same period in 2004

• Increased donations of $11 million due to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. Sharing of profits did not begin until the second quarter of 2004

• Increased purchased power expenses of $7 million, due primarily to increased outage and maintenance work at generating plants. Purchases are made when it is more economical than dispatching higher cost generating units, and

• Increased fuel expenses of $6 million, due primarily to increased coal costs. Generation fueled by coal accounted for more than 50 percent of total generation during the first quarter of both 2005 and 2004 and the delivered cost of coal in 2005 is approximately $7 per ton higher than the same period in 2004.

EBIT. EBIT for the three months ended March 31, 2005 decreased compared to the same period in 2004, due primarily to the timing of operating and maintenance expenses, sharing of profits from wholesale sales in 2005 but not in 2004, milder weather and increased regulatory amortization. These changes were partially offset by continued growth in the number of residential and general service customers.

Natural Gas Transmission

	Three Months Ended March 31,
(in millions, except where noted)	2005		2004		Increase (Decrease)
Operating revenues	$	1,191	$	1,053	$	138
Operating expenses		789		649		140
Gains on sales of other assets, net		3		—		3
Operating income		405		404		1
Other income, net of expenses		15		7		8
Minority interest expense		9		9		—
EBIT	$	411	$	402	$	9
Proportional throughput, TBtua		1,056		1,089		(33	)

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, 2005 as Compared to March 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $97 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas Limited (Union Gas). This revenue increase is offset in expenses

• A $57 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $6 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• An $8 million decrease at Union Gas primarily resulting from a new earnings-sharing mechanism effective January 1, 2005 (see Note 14 to the Consolidated Financial Statements, “Regulatory Matters”).

Operating Expenses. The increase was driven primarily by:

• A $97 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues, and

• A $44 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above).

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

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EBIT.EBIT increased primarily as a result of earnings from expansion projects and foreign exchange EBIT impacts from the strengthening Canadian currency, partly offset by lower revenues at Union Gas due to the new earnings-sharing mechanism.

Field Services

	Three Months Ended March 31,
(in millions, except where noted)	2005		2004		Increase (Decrease)
Operating revenues	$	2,658	$	2,339	$	319
Operating expenses		2,573		2,217		356
Gains on sales of other assets, net		2		—		2
Operating income		87		122		(35	)
Other income, net of expenses		1,251		17		1,234
Minority interest expense		420		51		369
EBIT	$	918	$	88	$	830
Natural gas gathered and processed/transported, TBtu/da		6.7		6.7		—
NGL production, MBbl/db		360		345		15
Average natural gas price per MMBtuc, d, e	$	6.27	$	5.69	$	0.58
Average NGL price per gallond, e	$	0.73	$	0.59	$	0.14

a Trillion British thermal units per day

b Thousand barrels per day

c Million British thermal units

d Index-based market price

e Does not reflect results of commodity hedges.

Three months ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues. The increase was primarily driven by:

• A $150 million increase due to a $0.14 per gallon increase in average NGL prices

• A $115 million increase due to a $0.58 per MMBtu increase in average natural gas prices

• A $25 million increase attributable to a $14.93 per-barrel increase in average crude oil prices to $50.10 during the three months ended March 31, 2005 from $35.17 during the same period in 2004

• A $19 million increase related to the impact of cash flow hedging, which reduced revenues by approximately $27 million for the three months ended March 31, 2005 and by approximately $46 million for the same period in 2004

• A $15 million increase in wholesale propane marketing activity primarily due to higher propane prices, partially offset by

• A $10 million decrease related to lower natural gas sales volumes, partially offset by higher NGL sales volumes and the acquisition of gathering and processing assets in southeast New Mexico from ConocoPhillips.

Operating Expenses. The increase was driven primarily by:

• A $210 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices

• An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”). After the discontinuance of these hedges, changes in their fair value will be recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from Field Services results

• A $10 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds, and

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

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

• A $1,142 million pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Energy’s limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.

Minority Interest Expense.Minority interest expense increased by $368 million due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion. The overall increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT resulted primarily from the gain on sale of TEPPCO GP and the favorable effects of commodity price increases. Also during the first three months of 2005, Duke Energy discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”). As a result of the discontinuance of hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Duke Energy in the first three months of 2005.

Matters Impacting Future Field Services Results

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7 % interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. While the specifics of the transaction are still being negotiated, DEFS expects to receive cash from ConocoPhillips. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method after the transaction closes. The transaction, which is subject to customary U.S. and Canadian regulatory approval, has a target close date of June 30, 2005. This transaction is estimated to result in a pre-tax gain to Field Services of approximately $600 million. As a result, Duke Energy expects to deconsolidate its investment in DEFS subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips.

DENA

	Three Months Ended March 31,
(in millions, except where noted)	2005		2004			Increase (Decrease)
Operating revenues	$	—	$	17		$	(17	)
Operating expenses		—		106			(106	)
Gains (Losses) on sales of other assets, net		—		(353	)		353
Operating loss		—		(442	)		442
Minority interest benefit		—		(12	)		12
EBIT	$	—	$	(430	)	$	430
Actual plant production, GWh				885			(885	)
Proportional megawatt capacity in operation				9,085			(9,085	)

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. DENA’s continuing operations for 2004 are included as a component of DENA’s segment earnings. The results of DENA’s discontinued operations for 2004 and 2005 are presented in Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in “Consolidated Income from Discontinued Operations, net of tax” above.

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Three Months Ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues. The decrease was driven primarily by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $45 million of power generation revenues, and

• ($28) million of other operating revenues, primarily driven by negative net trading margin at DETM.

Operating Expenses. The decrease was driven by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $32 million of fuel costs

• $52 million of operations, maintenance and depreciation expenses, and

• $22 million of general and administrative expenses.

Gains on Sales of Other Assets, net. The change was due to the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results were due primarily to a pre-tax loss of approximately $360 million associated with the sale of the Southeast Plants.

Minority Interest Benefit.The decrease was driven by the inclusion of DENA’s 2005 results of continuing operations in Other. The minority interest benefit in the 2004 results of continuing operations was related to DETM.

EBIT. The increase was driven by the inclusion of DENA’s 2005 results of continuing operations in Other, as discussed above.

International Energy

	Three Months Ended March 31,
(in millions, except where noted)	2005		2004		Increase (Decrease)
Operating revenues	$	168	$	154	$	14
Operating expenses		119		131		(12	)
Operating income		49		23		26
Other income, net of expenses		21		9		12
Minority interest expense		2		3		(1	)
EBIT	$	68	$	29	$	39
Sales, GWh		4,535		4,564		(29	)
Proportional megawatt capacity in operation		4,139		4,121		18

Three Months Ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues.The increase was driven primarily by:

• A $5 million increase due to higher energy prices and newly contracted energy in Guatemala

• A $7 million net increase resulting from an $11 million increase due to higher energy prices offset by a $9 million decrease in energy volumes and a $5 million increase due to favorable exchange rates in Brazil, and

• A $2 million increase due to higher distributor demand in Peru.

Operating Expenses.Operating expenses for the three months ended March 31, 2005 decreased $12 million, compared to the same period in 2004. The decrease is mainly a result of a $13 million charge associated with the disposition of the ownership share in the Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) nitrogen facility in Mexico recorded in 2004.

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

• A $6 million increase in equity income from the National Methanol Company investment due to higher methanol margins, and

• A $4 million increase in equity income from the Campeche investment due to increased natural gas processing volumes and decreased maintenance costs.

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EBIT. EBIT for the three months ended March 31, 2005 increased $39 million, compared to the same period in 2004. This increase was due primarily to the absence of the charge associated with the Cantarell disposition, higher earnings in Brazil, Peru and Guatemala and increased equity income from National Methanol Company and Campeche.

Crescent

	Three Months Ended March 31,
(in millions)	2005		2004		Increase (Decrease)
Operating revenues	$	64	$	38	$	26
Operating expenses		51		36		15
Gains on sales of investments in commercial and multi-family real estate		42		59		(17	)
Operating income		55		61		(6	)
Minority interest expense		3		1		2
EBIT	$	52	$	60	$	(8	)

Three Months Ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues. The increase was driven primarily by a $28 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina, The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina, the LandMar division in northeastern and central Florida and the Lake James projects in northwestern North Carolina.

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

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

• A $20 million decrease in commercial project sales due to the sale of a commercial project in the Washington, DC area in the first quarter of 2004 as compared to no project sales in the first quarter of 2005, partially offset by

• A $3 million increase in legacy land sales due to several large tract sales closed in the first quarter of 2005.

EBIT. As discussed above, the decrease in EBIT was driven primarily by the sale of a commercial project in the Washington, DC area in the first quarter of 2004 as compared to no project sales in the first quarter of 2005, partially offset by an increase in residential developed lot sales and an increase in legacy land sales.

Other

	Three Months Ended March 31,
(in millions)	2005			2004			Increase (Decrease)
Operating revenues	$	47		$	344		$	(297	)
Operating expenses		256			387			(131	)
Gains on sales of other assets, net		3			14			(11	)
Operating income		(206	)		(29	)		(177	)
Other income, net of expense		3			24			(21	)
Minority interest benefit		(1	)		—			(1	)
EBIT	$	(202	)	$	(5	)	$	(197	)

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to

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the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended March 31, 2005 increased Other’s segment losses by approximately $30 million.

Three Months Ended March 31, 2005 as Compared to March 31, 2004

Operating Revenues. The decrease was driven primarily by:

• A $196 million decrease in revenue as a result of the continued wind-down of DEM, and

• An approximate $110 million decrease as a result of the mark-to-market impact of certain cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were discontinued and transferred to Other (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”).

Operating Expenses. The decrease was driven primarily by:

• A $201 million decrease as a result of the continued wind-down of DEM, partially offset by

• A $47 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s expenses from continuing operations consist of $10 million of fuel costs, $16 million of general and administrative expenses, and $21 million of operations, maintenance and depreciation expenses, and

• A $28 million mutual insurance liability adjustment related to Bison which was an immaterial correction of an accounting error related to prior periods.

Gains on Sales of Other Assets, net.Gains on sales of other assets for the three months ended March 31, 2005 decreased due primarily to a $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad) in 2004.

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

• A $10 million decrease in earnings from executive life insurance, and

• A $10 million decrease in equity earnings from D/FD as a result of the wind-down of the partnership.

EBIT.EBIT for the three months ended March 31, 2005 decreased $197 million compared to the same period in 2004. The decrease was due primarily to the mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk. This decrease was also due to the movement of DENA’s continuing operations to Other in 2005, as discussed above and the mutual insurance liability adjustments, as discussed above.

Matters Impacting Future Other Results

Based on prices as of March 31, 2005, approximately $150 million of unrealized losses recognized on the discontinuance and subsequent mark-to-market of certain Field Services commodity price risk contracts in the first quarter of 2005 are for contracts that are expected to settle by the end of 2005. Future Other results will be subject to volatility as a result of future mark-to-market changes on these and certain other contracts related to the economic hedging of Field Services’ commodity price risk.

Other Impacts on Earnings Available for Common Stockholders

Interest expense decreased $53 million for the three months ended March 31, 2005, compared to the same period in 2004, due primarily to Duke Energy’s lower debt balance in 2005.

Minority interest expense increased $380 million for the three months ended March 31, 2005, compared to the same period in 2004, due primarily to increased earnings at DEFS as a result of the sale of TEPPCO GP.

Income tax expense increased $375 million for the three months ended March 31, 2005, compared to the same period in 2004, due primarily to the $1,073 million increase in earnings from continuing operations. The effective tax rate increased to 34.4% for the three months ending March 31, 2005 as compared to 31.9% for the same period in 2004. (See Note 18 to the Consolidated Financial Statements, “Income Tax Expense”.)

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Income from discontinued operations decreased $141 million for the three months ended March 31, 2005, compared to the same period in 2004. This decrease was due primarily to a $238 million after-tax gain that was recorded in the first quarter of 2004 on the sale of International Energy’s Asia-Pacific Business, partially offset by a $104 million after-tax favorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified to discontinued operations as a result of the DENA exit plan. (See Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.”)

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. (See Note 3 to the Consolidated Financial Statements, “Common Stock”.)

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $270 million for the three months ended March 31, 2005, compared to the same period in 2004, due primarily to decreased cash flow from changes in working capital. Cash flow from changes in working capital for the 2005 period was lower than the 2004 period due primarily to approximately $170 million more collateral posted to counterparties by Duke Energy in 2005 partially offset by approximately $20 million more of collateral posted by counterparties to Duke Energy in 2005, and the contraction of business at DENA in 2004, which resulted in less cash collected from receivables in 2005 partially offset by less cash paydowns of accounts payable. Cash provided by operating activities also decreased due to an increase of approximately $52 million in cash outflow associated with North Carolina clean-air legislation. Cash outflow associated with this legislation was approximately $63 million for the three months ended March 31, 2005, compared to approximately $11 million for the same period in 2004. These decreases in cash provided by operating activities were partially offset by an approximate $30 million decrease in taxes paid in 2005.

Investing Cash Flows

Net cash provided by investing activities increased approximately $1.3 billion for the three months ended March 31, 2005, compared to the same period in 2004. Of this increase, $1.2 billion related to proceeds from the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, $310 million from net proceeds associated with available-for-sale securities and $161 million from decreased capital expenditures. These increases to cash were partially offset by a $116 million decrease in proceeds from sales of commercial and multi-family real estate associated with several large land sales that closed in the first quarter of 2004 and $162 million in cash settlements associated with net investment hedges in 2005.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased $844 million for the three months ended March 31, 2005, compared to same period in 2004. This change was due primarily to the repurchase of 30 million shares of common stock for approximately $834 million, including approximately $10 million in commissions and other fees in March 2005. (See Note 3 to the Consolidated Financial Statements, “Common Stock”.)

Cash generated from operations, the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, and DEFS transactions are expected to be adequate for funding Duke Energy’s capital expenditures, dividend payments, and share repurchases for 2005.

With cash, cash equivalents and short-term investments on hand at March 31, 2005 of approximately $2.1 billion and a more stable business environment, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy continues to evaluate these options to determine the best economic decision to meet the

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needs of shareholders and the long-term financial strength of Duke Energy. In connection with the share repurchase program announced in February of 2005 of up to $2.5 billion, Duke Energy has entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. Duke Energy also entered into a separate open market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of March 31, 2005, through this open market purchase plan with the investment bank, Duke Energy had repurchased no shares of its common stock. At April 30, 2005, Duke Energy had repurchased 1.6 million shares of its common stock through this plan at a weighted average price of $28.80 per share. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment.

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

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

During the three-month period ended March 31, 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

Available Credit Facilities and Restrictive Debt Covenants.Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of March 31, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

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

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Credit Ratings Summary as of May 1, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
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.	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 capital and investment expenditures and dividends, and a disciplined execution of the $2.5 billion share repurchase program, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.

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 conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participates in DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy.

A reduction in DETM’s credit rating to below investment grade as of March 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $180 million. Additionally, in the event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of March 31, 2005, Duke Capital would have been required to escrow approximately $320 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Energy’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of March 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $280 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to termination of the agreements. As of March 31, 2005, Duke Capital could have been required to pay up to $10 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.

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

Other Financing Matters.As of March 31, 2005, Duke Energy and its subsidiaries had effective Securities and Exchange Commission (SEC) shelf registrations for up to $1,542 million in gross proceeds from debt and other securities. The total amount available under effective shelf registrations decreased $500 million during the first quarter of 2005 resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of March 31, 2005, Duke Energy had access to 900 million Canadian dollars (approximately U.S. $744 million) available under the Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 500 million Canadian dollars will expire in November 2005 and 400 million Canadian dollars will expire in July 2006.

Off-Balance Sheet Arrangements

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction for 30 million shares as part of its publicly announced share repurchase program that allows Duke Energy to purchase up to $2.5 billion of its common stock over the next three years. In connection with this transaction, Duke Energy simultaneously entered into a forward sale contract with an investment bank that is indexed to and potentially settled in its own common stock. The forward sale contract is a derivative instrument and is classified as equity and is therefore considered to be an off-balance sheet arrangement (see Note 3 to the Consolidated Financial Statements, “Common Stock”). For additional information on Duke Energy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Duke Energy’s Annual Report on Form 10-K for the year-ended December 31, 2004.

Contractual Obligations and Commercial Commitments

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

OTHER ISSUES

Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Energy has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6% below their 1990 level over the period 2008 to 2012. In anticipation of the Kyoto Protocol’s entry into force, the Canadian government recently released a proposal for an implementation plan that includes, among other things, an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (LFE). Consultation to develop the plan details is scheduled to begin this spring. If an LFE program is ultimately enacted, then all of Duke Energy’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of Carbon Dioxide (CO2) emission credits to actual emission reductions at the source, or a combination of strategies.

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

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

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

(For additional information on other issues related to Duke Energy, see Note 14 to the Consolidated Financial Statements, “Regulatory Matters” and Note 15 to the Consolidated Financial Statements, “Commitments and Contingencies”.)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of March 31, 2005:

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

The impact on EPS for the three-month periods ended March 31, 2005 and 2004 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed in the Pro Forma Stock-Based Compensation table included in Note 4 to the Consolidated Financial Statements, “Stock-Based Compensation”. Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Energy does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new equity-based compensation awards issued to employees.

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

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 29’s concept of culmination of an earning process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. SFAS No. 153 does not apply to transfers of nonmonetary assets between entities under common control. The impact to Duke Energy of adopting SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Energy does not currently expect adoption of SFAS No. 153 will have a material impact on its consolidated results of operations, cash flows or financial position.

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FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations”. In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. Duke Energy is currently evaluating the impact of adopting FIN 47 as well as the interim transition provisions and cannot currently estimate the impact of FIN 47 on its consolidated results of operations, cash flows or financial position.

Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-Q for the quarter ended March 31, 2005, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

Acquisitions and Dispositions - Field Services . In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP) for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion and Minority Interest Expense of $343 million to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. During 2005, Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $.8 billion in cash and approximately $.3 billion of assets. The DEFS disposition resulted in pre-tax gain of approximately $575 million in third quarter 2005. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. In connection with the DEFS disposition, Duke Energy acquired ConocoPhillips interest in the Empress System gas processing and natural gas liquids marketing business (Empress System) in August 2005 for cash of approximately $230 million.

Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see also Note 9 to the Consolidated Financial Statements).

As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market. As a result, approximately $355 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy in the nine months ended September 30, 2005. Upon the discontinuance of hedge accounting, approximately $120 million of pre-tax charges were recognized while approximately $235 million of losses have been recognized subsequent to discontinuance of hedge accounting.

Acquisitions and Dispositions - DENA.As described in Note 11 to the Consolidated Financial Statements, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

• The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)

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• The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan, and

• Pre-tax impairments of approximately $0.6 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon information from third party valuations and internal valuations.

In addition to these amounts, at September 30, 2005, approximately $150 million of pre-tax deferred net gains remain in AOCI related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings over the next 12 months as the forecasted transactions occur. In addition, management anticipates that additional charges will be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts estimated at approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs. The actual amount of future additional charges related to the DENA exit plan will vary depending on changes in market conditions and other factors, and could differ from management’s current expectation.

DENA may also realize future potential gains on sales of certain plants which will be recognized when sold. Subsequent to September 30, 2005, DENA has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. Included in the estimated exit costs are the effects of DENA’s November 17, 2005 agreement to sell to Barclays Bank PLC (Barclays) substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and contracts related to DENA’s energy marketing and management activities. Excluded from the sale to Barclays are commodity contracts associated with the near-term value of DENA’s west and northeastern generation assets and with remaining gas transportation and structured power contracts. Among other things, the agreement provides that effective November 17, 2005 all economic benefits and burdens under the contracts were transferred to Barclays. DENA agreed to pay Barclays cash consideration of approximately $700 million by January 3, 2006 and as the contracts are novated, assigned or terminated, all net collateral posted by DENA under those contracts will be returned to DENA. Net cash collateral to be returned to DENA is expected to substantially offset the cash consideration to be paid to Barclays. The novation or assignment of physical power contracts is subject to Federal Energy Regulatory Commission approval.

As of September 30, 2005, DENA’s assets and liabilities to be disposed of under the exit plan, were classified as Assets Held for Sale and consisted of the following:

Summarized DENA Assets and Associated Liabilities Held for Sale As of September 30, 2005 (in millions)

Current assets	$	1,579
Investments and other assets		1,556
Net property, plant and equipment		1,151
Total assets held for sale	$	4,286
Current liabilities	$	1,605
Long-term debt and other deferred credits		2,260
Total liabilities associated with assets held for sale	$	3,865

In October 2005, the Ft. Frances generation facility was sold to a third party for proceeds which approximate the carrying value of the sold assets.

Acquisitions and Dispositions - Cinergy Merger.On May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at September 30, 2005, the holding company would issue approximately 310 million shares to convert the Cinergy common shares. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, had the transaction closed as of September 30, 2005, it would have been valued approximately as follows:

Pro forma Cinergy Merger Transaction Value

Value of common stock and other consideration provided	$	9 billion
Fair value of net assets acquired		5 billion
Incremental goodwill from Cinergy acquisition	$	4 billion

The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including approval of shareholders of both companies and a number of federal and state governmental authorities. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to

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making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

Additionally, Duke Energy has announced plans to suspend additional repurchases under its open market share purchase plan pending further assessment, as discussed in Note 3.

Acquisitions and Dispositions – Natural Gas Transmission: In April 2005, Natural Gas Transmission agreed to acquire natural gas storage and pipeline assets in southwest Virginia and a 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. Upon closing of this transaction, which is estimated to be in the third quarter of 2005, Natural Gas Transmission will own 100% of Saltville Storage.

For information on subsequent events related to common stock, debt and credit facilities, regulatory matters, and litigation see Notes 3, 6, 14 and 15.

Part I, Item 3.Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

Normal Purchases and Normal Sales. The unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption was approximately $1,370 million as of March 31, 2005 and $900 million as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized net gains on natural gas and power cash flow hedge positions of approximately $1,080 million as March 31, 2005 and $750 million as of December 31, 2004, which are recorded on the Consolidated Balance Sheets in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. A key objective for Duke Energy in 2005 is to position DENA to be a successful merchant operator. Duke Energy is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. Depending on the options selected, there is a risk that material impairments or other losses could be recorded, including the potential disqualification of DENA’s power forward sales contracts designated under the normal purchases and normal sales exemption. This would result in the recognition of all unrealized losses associated with these forward contracts. See Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

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

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

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Daily Earnings at Risk (in millions)

	March 31, 2005 One-Day Impact on Operating Income for 2005a		Estimated Average One- Day Impact on Operating Income for 1st Quarter 2005 a		Estimated Average One- Day Impact on Operating Income for the Year 2004a		High One-Day Impact on Operating Income for 1st Quarter 2005a		Low One-Day Impact on Operating Income for 1st Quarter 2005a
Calculated DER	$	4	$	5	$	16	$	8	$	2

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

The DER figures above do not include the hedges which were de-designated as a result of the anticipated transfer of 19.7% of Duke Energy’s interest in Duke Energy Field Services, LLC to ConocoPhillips. (See further discussion in Note 13, “Risk Management Instruments,” to the Consolidated Financial Statements.)

Credit Risk

In 1999, the Industrial Development Corp of the City of Edinburg, TX (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo, a subsidiary of Duke Capital, and Duke Capital unconditionally and irrevocably guaranteed the lease payments due to IDC from Duke Hidalgo. In 2000, Duke Hidalgo was sold to Calpine Corporation and Duke Capital remained responsible for its lease guaranty obligations. Calpine Corporation has provided an indemnification to backstop Duke Capital’s lease guaranty obligations. Total maximum exposure under this guarantee obligation as of March 31, 2005 is approximately $200 million.

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