UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For quarter ended June 30, 2005 Commission file number 1-4928

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

North Carolina	56-0205520
(State or other jurisdiction of incorporation)	(IRS Employer Identification No.)
526 South Church Street, Charlotte, NC	28202-1803
(Address of principal executive offices)	(Zip Code)

704-594-6200

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes x No ¨

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

Number of shares of Common Stock, without par value, outstanding as of August 3, 2005…926,384,018

INDEX

DUKE ENERGY CORPORATION

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2005

Item		Page
PART I. FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004	1
	CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2005 AND DECEMBER 31, 2004	2
	CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004	4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	5
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
4.	CONTROLS AND PROCEDURES	61
PART II. OTHER INFORMATION
1.	LEGAL PROCEEDINGS	62
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	62
4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	62
6.	EXHIBITS	63
	SIGNATURES	65

SAFE HARBOR STATEMENT UNDER THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

Duke Energy Corporation’s reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Energy’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Energy’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

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

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

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

• The weather and other natural phenomena

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

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

• Changes in environmental and other laws and regulations to which Duke Energy and its subsidiaries are subject or other external factors over which Duke Energy has no control

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

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

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

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

• Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop real estate, domestic and international power, pipeline, gathering, processing and other infrastructure projects

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

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

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

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

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

• The ability to successfully complete merger, acquisition or divestiture plans (including the merger with Cinergy Corp.); regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

DUKE ENERGY CORPORATION

Consolidated Statements of Operations

(Unaudited)

(In millions, except per-share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	3,687		$	3,391		$	7,010		$	6,768
Regulated electric		1,237			1,269			2,512			2,521
Regulated natural gas and natural gas liquids		730			656			1,881			1,663
Total operating revenues		5,654			5,316			11,403			10,952
Operating Expenses
Natural gas and petroleum products purchased		2,838			2,558			5,861			5,547
Operation, maintenance and other		950			827			1,814			1,611
Fuel used in electric generation and purchased power		490			605			922			1,169
Depreciation and amortization		486			420			992			854
Property and other taxes		149			124			309			278
Impairment and other charges		2			3			123			3
Total operating expenses		4,915			4,537			10,021			9,462
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		12			62			54			121
(Losses) Gains on Sales of Other Assets, net		—			(11	)		33			(349	)
Operating Income		751			830			1,469			1,262
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		39			42			80			77
Gains on sales of equity investments		6			—			1,245			—
Other income and expenses, net		40			47			65			72
Total other income and expenses		85			89			1,390			149
Interest Expense		297			336			590			692
Minority Interest Expense		77			43			493			81
Earnings From Continuing Operations Before Income Taxes		462			540			1,776			638
Income Tax Expense from Continuing Operations		151			134			598			167
Income From Continuing Operations		311			406			1,178			471
Discontinued Operations
Net operating (loss) income, net of tax		(2	)		(4	)		(1	)		3
Net gain on dispositions, net of tax		—			30			—			269
(Loss) Income From Discontinued Operations		(2	)		26			(1	)		272
Net Income		309			432			1,177			743
Dividends and Premiums on Redemption of Preferred and Preference Stock		2			3			4			5
Earnings Available For Common Stockholders	$	307		$	429		$	1,173		$	738
Common Stock Data
Weighted-average shares outstanding
Basic		927			926			941			919
Diluted		964			961			977			954
Earnings per share (from continuing operations)
Basic	$	0.33		$	0.43		$	1.25		$	0.50
Diluted	$	0.32		$	0.42		$	1.20		$	0.49
Earnings per share (from discontinued operations)
Basic	$	—		$	0.03		$	—		$	0.30
Diluted	$	—		$	0.03		$	—		$	0.29
Earnings per share
Basic	$	0.33		$	0.46		$	1.25		$	0.80
Diluted	$	0.32		$	0.45		$	1.20		$	0.78
Dividends per share	$	0.585		$	0.550		$	0.860		$	0.825

See Notes to Consolidated Financial Statements

1

PART I

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(Unaudited)

(In millions)

	June 30,		December 31,
	2005		2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,009	$	533
Short-term investments		1,040		1,319
Receivables (net of allowance for doubtful accounts of $130 at June 30, 2005 and $135 at December 31, 2004)		2,905		3,237
Inventory		957		942
Assets held for sale		15		40
Unrealized gains on mark-to-market and hedging transactions		1,021		962
Other		1,015		938
Total current assets		7,962		7,971
Investments and Other Assets
Investments in unconsolidated affiliates		1,318		1,292
Nuclear decommissioning trust funds		1,410		1,374
Goodwill		4,106		4,148
Notes receivable		162		232
Unrealized gains on mark-to-market and hedging transactions		1,731		1,379
Assets held for sale		63		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $15 at June 30, 2005 and $15 at December 31, 2004)		1,354		1,128
Other		1,977		1,896
Total investments and other assets		12,121		11,533
Property, Plant and Equipment
Cost		46,894		46,806
Less accumulated depreciation and amortization		13,504		13,300
Net property, plant and equipment		33,390		33,506
Regulatory Assets and Deferred Debits
Deferred debt expense		281		297
Regulatory assets related to income taxes		1,296		1,269
Other		945		894
Total regulatory assets and deferred debits		2,522		2,460
Total Assets	$	55,995	$	55,470

See Notes to Consolidated Financial Statements

2

PART I

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(Unaudited)

(In millions)

	June 30, 2005		December 31, 2004
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	2,224	$	2,414
Notes payable and commercial paper		84		68
Taxes accrued		520		273
Interest accrued		288		287
Liabilities associated with assets held for sale		—		30
Current maturities of long-term debt and preferred stock		1,925		1,832
Unrealized losses on mark-to-market and hedging transactions		777		819
Other		1,981		1,815
Total current liabilities		7,799		7,538
Long-term Debt		16,359		16,932
Deferred Credits and Other Liabilities
Deferred income taxes		5,661		5,228
Investment tax credit		149		154
Unrealized losses on mark-to-market and hedging transactions		1,041		971
Liabilities associated with assets held for sale		14		14
Asset retirement obligations		2,007		1,926
Other		4,625		4,646
Total deferred credits and other liabilities		13,497		12,939
Commitments and Contingencies
Minority Interests		1,925		1,486
Preferred and preference stock without sinking fund requirements		134		134
Common Stockholders’ Equity
Common stock, no par, 2 billion shares authorized; 926 million and 957 million shares outstanding at June 30, 2005 and December 31, 2004, respectively		10,375		11,252
Retained earnings		4,962		4,539
Accumulated other comprehensive income		944		650
Total common stockholders’ equity		16,281		16,441
Total Liabilities and Common Stockholders’ Equity	$	55,995	$	55,470

See Notes to Consolidated Financial Statements

3

PART I

DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

(In millions)

	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,177		$	743
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,081			943
Gains on sales of investments in commercial and multi-family real estate		(54	)		(121	)
(Gains) losses on sales of equity investments and other assets		(1,281	)		64
Deferred income taxes		244			76
Minority Interest		484			68
Purchased capacity levelization		(5	)		100
Contribution to company-sponsored pension plans		(21	)		(6	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		142			150
Receivables		366			(50	)
Inventory		(11	)		104
Other current assets		(43	)		171
Increase (decrease) in
Accounts payable		(209	)		(293	)
Taxes accrued		332			452
Other current liabilities		(148	)		(18	)
Capital expenditures for residential real estate		(209	)		(138	)
Cost of residential real estate sold		109			80
Other, assets		(188	)		(87	)
Other, liabilities		228			133
Net cash provided by operating activities		1,994			2,371
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures		(1,050	)		(1,115	)
Purchases of available-for-sale securities		(20,787	)		(20,864	)
Proceeds from sales and maturities of available-for-sale securities		20,987			19,667
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,341			720
Proceeds from the sales of commercial and multi-family real estate		77			303
Settlement of net investment hedges		(162	)		—
Other		(10	)		(60	)
Net cash provided by (used in) investing activities		396			(1,349	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		4			112
Issuance of common stock and common stock related to employee benefit plans		28			947
Payments for the redemption of:
Long-term debt		(639	)		(1,138	)
Preferred stock of a subsidiary		—			(76	)
Notes payable and commercial paper		167			297
Distributions to minority interests		(377	)		(703	)
Contributions from minority interests		330			638
Dividends paid		(522	)		(526	)
Repurchase of common shares		(909	)		—
Other		3			2
Net cash used in financing activities		(1,915	)		(447	)
Changes in cash and cash equivalents associated with assets held for sale		1			40
Net increase in cash and cash equivalents		476			615
Cash and cash equivalents at beginning of period		533			397
Cash and cash equivalents at end of period	$	1,009		$	1,012
Supplemental Disclosures
Significant non-cash transactions:
Debt retired in connection with disposition of businesses	$	—		$	838
Remarketing of senior notes	$	—		$	875
Dividends declared but not paid	$	287		$	258

See Notes to Consolidated Financial Statements

4

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

(Unaudited)

1. Basis of Presentation

Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is a leading energy company located in the Americas with a real estate subsidiary. 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, pipelines and gas processing facilities, 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 to generally accepted accounting principles (GAAP) in the United States (U.S.), 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 Revisions. The accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2004 reflects a reclassification of instruments used in Duke Energy’s cash management program from cash and cash equivalents to short-term investments of $1,684 million and $763 million as of June 30, 2004 and December 31, 2003, respectively. 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.

Additionally, the accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2004 reflects a change in the classification of expenditures for equipment related to clean air legislation in the state of North Carolina from cash flows from operating activities to cash flows from investing activities. As a result, net cash provided by operating activities for the six months ended June 30, 2004 has increased by $21 million, while net cash used in investing activities for the six months ended June 30, 2004 increased by the same amount.

Certain other prior period amounts have also been reclassified to conform to the presentation for the current period.

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.

5

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 and six months ended June 30, 2005 and 2004.

	Income			Average Shares	EPS
	(in millions, except per-share data)
Three Months Ended June 30, 2005
Income from continuing operations	$	311
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)
Income from continuing operations—basic	$	309		927	$	0.33
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock, and common stock derivatives				4
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	311		964	$	0.32
Three Months Ended June 30, 2004
Income from continuing operations	$	406
Less: Dividends and premiums on redemption of preferred and preference stock		(3	)
Income from continuing operations—basic	$	403		926	$	0.43
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	405		961	$	0.42
Six Months Ended June 30, 2005
Income from continuing operations	$	1,178
Less: Dividends and premiums on redemption of preferred and preference stock		(4	)
Income from continuing operations—basic	$	1,174		941	$	1.25
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock, and common stock derivatives				3
Contingently convertible bond		4		33
Income from continuing operations—diluted	$	1,178		977	$	1.20
Six Months Ended June 30, 2004
Income from continuing operations	$	471
Less: Dividends and premiums on redemption of preferred and preference stock		(5	)
Income from continuing operations—basic	$	466		919	$	0.50
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		4		33
Income from continuing operations—diluted	$	470		954	$	0.49

6

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The increase in weighted-average shares outstanding for the six months ended June 30, 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. Offsetting this increase is the impact of Duke Energy’s repurchase and retirement of 30 million shares of its common stock in March 2005 through an accelerated share repurchase transaction, as discussed in Note 3.

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 June 30, 2004, from $0.46 to $0.45, and restated diluted earnings per share for the six months ended June 30, 2004, from $0.80 to $0.78.

Options, restricted stock, performance and phantom stock awards related to approximately 18 million shares as of June 30, 2005, and 26 million shares as of June 30, 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.

For the three and six months ended June 30, 2004, Duke Energy’s $750 million of Equity Units, which resulted in the issuance of approximately 19 million shares in November 2004, is not included in “effect of dilutive securities” in the above table because their inclusion would be antidilutive.

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. As of June 30, 2005, the investment bank had purchased approximately 20.4 million shares at a weighted average price of $28.28 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

7

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

factors, including the market price of Duke Energy’s common stock. As of June 30, 2005, Duke Energy had purchased approximately 2.6 million shares of its common stock pursuant to this plan at a weighted average price of $28.97 per share. On May 9, 2005, in connection with the proposed merger with Cinergy Corp. (Cinergy), Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. (For further discussion, see Note 9.)

On June 29, 2005, Duke Energy declared a quarterly cash dividend on its common stock of $0.31 per share, an increase of $0.035 cents per share above its previous level. The dividend is payable on September 16, 2005, to shareholders of record as of the close of business on August 12, 2005.

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.

Pro Forma Stock-Based Compensation

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	307		$	429		$	1,173		$	738
Add: stock-based compensation expense included in reported net income, net of related tax effects		9			3			16			6
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(9	)		(5	)		(16	)		(12	)
Pro forma earnings available for common stockholders, net of tax effects	$	307		$	427		$	1,173		$	732
EPS
Basic—as reported	$	0.33		$	0.46		$	1.25		$	0.80
Basic—pro forma	$	0.33		$	0.46		$	1.25		$	0.79
Diluted—as reported	$	0.32		$	0.45		$	1.20		$	0.78
Diluted—pro forma	$	0.32		$	0.45		$	1.20		$	0.77

5. Inventory

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

Inventory

	June 30,		December 31,
	2005		2004
	(in millions)
Materials and supplies	$	467	$	445
Natural gas		243		312
Coal held for electric generation		144		104
Petroleum products		103		81
Total inventory	$	957	$	942

8

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

6. Debt and Credit Facilities

In December 2004, Duke Energy reached an agreement to sell its partially completed Grays Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC (see Note 9). 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 first quarter of 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 those balances on a long-term basis.

Available Credit Facilities and Restrictive Debt Covenants. During the six-month period ended June 30, 2005, Duke Energy’s consolidated credit capacity increased by approximately $750 million compared to December 31, 2004. Duke Capital LLC (Duke Capital) and Duke Energy Field Services LLC (DEFS) renewed and replaced their credit facilities at higher levels to provide additional credit capacity. Duke Capital added a new $100 million, 364 day bilateral credit facility to provide additional letter of credit issuing capacity and increased its expiring 364 day letter of credit facility by $200 million. In addition, Duke Capital added three new 364 day credit facilities totaling $260 million to provide additional credit support. DEFS increased its expiring 364 day credit facility by $200 million. Westcoast Energy Inc. (Westcoast) and Union Gas Limited (Union Gas) renewed and replaced their credit facilities at existing levels. Duke Energy and Duke Capital amended their respective multi-year syndicated facilities to extend the expiration dates.

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 June 30, 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.

9

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Credit Facilities Summary as of June 30, 2005

				Amounts Outstanding
	Expiration Date	Credit Facilities Capacity
				Commercial Paper		Letters of Credit		Total
	(in millions)
Duke Energy
$150 two-year bilateral (a), (b)	September 2005
$500 multi-year syndicated (a), (b), (c)	June 2010
Total Duke Energy		$	650	$	384	$	—	$	384
Duke Capital LLC
$800 364-day syndicated (a), (b)	June 2006
$600 multi-year syndicated (a), (b), (d)	June 2009
$130 three-year bi-lateral (b)	October 2007
$120 multi-year bi-lateral (b)	July 2009
$100 364-day bi-lateral (b)	June 2006
$260 364-day bi-laterals (a), (b)	June 2006
Total Duke Capital LLC			2,010		—		781		781
Westcoast Energy Inc.
$81 364-day syndicated (b), (e)	June 2006
$162 multi-year syndicated (b), (c), (f)	June 2010
Total Westcoast Energy Inc.			243		—		—		—
Union Gas Limited
$243 364-day syndicated (g), (h)	June 2006		243		—		—		—
Duke Energy Field Services LLC
$450 multi-year syndicated (i), (j), (k)	April 2010		450		—		—		—
Total		$	3,596	$	384	$	781	$	1,165

(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) In June 2005, credit facility expiration date was extended from June 2007 to June 2010.

(d) In June 2005, credit facility expiration date was extended from June 2007 to June 2009.

(e) Credit facility is denominated in Canadian dollars totaling 100 million Canadian dollars.

(f) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars.

(g) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars totaling 300 million Canadian dollars.

(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 but not exceeding 18 months from the date of draw.

(i) 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.

(j) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 60%.

(k) Credit facility contains an interest coverage covenant.

10

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 Canadian retirement plans.

Components of Net Periodic Pension Costs (Income)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Duke Energy U.S.
Service cost	$	16		$	16		$	31		$	32
Interest cost on projected benefit obligation		40			40			79			80
Expected return on plan assets		(57	)		(58	)		(114	)		(116	)
Amortization of prior service cost credit		(1	)		(1	)		(1	)		(1	)
Amortization of net transition asset		—			(1	)		—			(2	)
Amortization of losses		8			4			17			7
Curtailment gain		—			—			—			(1	)
Net periodic pension costs (income)	$	6		$	—		$	12		$	(1	)
Westcoast
Service cost	$	2		$	2		$	4		$	4
Interest cost on projected benefit obligation		8			6			15			13
Expected return on plan assets		(7	)		(6	)		(13	)		(12	)
Amortization of loss		1			1			2			1
Net periodic pension costs	$	4		$	3		$	8		$	6

Duke Energy’s policy is to fund amounts for its U.S. retirement plan on an actuarial basis to provide sufficient assets to meet benefit payments to plan participants. Duke Energy has not made contributions to its U.S. retirement plan for the three and six month periods ended June 30, 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 its 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 $8 million and $19 million to the Westcoast DB plans for the three and six month periods ended June 30, 2005, respectively. Duke Energy anticipates that it will make total contributions of approximately $37 million in 2005. Duke Energy has contributed $1 million and $2 million to the Westcoast DC plans for the three and six month periods ended June 30, 2005, respectively, and anticipates that it will make total contributions of approximately $3 million in 2005.

11

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

Components of Net Periodic Post-Retirement Benefit Costs

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Duke Energy U.S.
Service cost benefit	$	2		$	1		$	3		$	3
Interest cost on accumulated post- retirement benefit obligation		12			11			23			24
Expected return on plan assets		(5	)		(5	)		(9	)		(9	)
Amortization of net transition liability		4			4			8			8
Amortization of losses		2			2			4			5
Net periodic post-retirement benefit costs	$	15		$	13		$	29		$	31
Westcoast
Service cost benefit	$	—		$	1		$	1		$	1
Interest cost on accumulated post- retirement benefit obligation		1			1			2			2
Amortization of loss		1			—			1			1
Net periodic post-retirement benefit costs	$	2		$	2		$	4		$	4

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy expensed employer matching contributions of $14 million for the three month period ended June 30, 2005 compared to $14 million for the three month period ended June 30, 2004. Duke Energy expensed employer matching contributions of $34 million for the six month period ended June 30, 2005 compared to $32 million for the six month period ended June 30, 2004.

8. Comprehensive Income and Accumulated Other Comprehensive Income

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

Total Comprehensive Income

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005		2004
	(in millions)
Net Income	$	309		$	432		$	1,177	$	743
Other comprehensive income
Foreign currency translation adjustments (a)		9			(241	)		56		(284	)
Net unrealized gains on cash flow hedges (b)		93			52			236		179
Reclassification into earnings from cash flow hedges (c)		(57	)		(60	)		2		(54	)
Other comprehensive income (loss), net of tax		45			(249	)		294		(159	)
Total Comprehensive Income	$	354		$	183		$	1,471	$	584

(a) Foreign currency translation adjustments, net of $62 million tax benefit for the six months ended June 30, 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 $49 million and $14 million tax expense for the three months ended June 30, 2005 and 2004, respectively, and $123 million and $66 million tax expense for the six months ended June 30, 2005 and 2004, respectively.

(c) Reclassification into earnings from cash flow hedges, net of $29 million and $21 million tax benefit for the three months ended June 30, 2005 and 2004, respectively, and $1 million tax expense and $18 million tax benefit for the six months ended June 30, 2005 and 2004, respectively.

12

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Accumulated Other Comprehensive Income (AOCI). The following table shows the components of and changes in AOCI.

Components of and Changes in AOCI

	Foreign Currency Adjustments		Net Gains on Cash Flow Hedges		Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income
	(in millions)
Balance as of December 31, 2004	$	540	$	526	$	(416	)	$	650
Other comprehensive income changes year- to-date (net of tax expense of $62)		56		238		—			294
Balance as of June 30, 2005	$	596	$	764	$	(416	)	$	944

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.

On May 9, 2005, Duke Energy and Cinergy announced they have 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 June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. 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, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $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 the approval of shareholders of both companies and a number of federal and state governmental authorities. See further discussion of regulatory filings in Note 14. 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.

In April 2005, Duke Energy’s Natural Gas Transmission business unit agreed to acquire natural gas storage and pipeline assets in southwest Virginia and an additional 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 expected to occur in the third quarter of 2005, Natural Gas Transmission will own 100% of Saltville Storage.

In the second quarter 2005, United Bridgeport Energy, LLC (UBE), the owner of a 33 ¹/3% interest in Bridgeport Energy, LLC (Bridgeport), exercised its “put right” requiring Duke Energy North America (DENA) to purchase UBE’s interest in Bridgeport as provided for in the LLC Agreement. DENA and UBE are currently negotiating the purchase price of UBE’s ownership interest. Upon closing of this transaction, DENA will own 100% of Bridgeport.

Dispositions. For the three months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $20 million in proceeds, and pre-tax gains of $6 million recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. For the six months ended June 30, 2005, the sale of other assets, businesses and equity

13

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

investments resulted in approximately $1.3 billion in proceeds, net pre-tax gains of $33 million recorded in (Losses) Gains on Sales of Other Assets, net and pre-tax gains of approximately $1.2 billion recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 11, and commercial and multi-family real estate sales by Crescent Resources LLC (Crescent) which are discussed separately below. Significant sales of other assets and equity investments during the six months ended June 30, 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 six months ended June 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the six months ended June 30, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of 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. Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion in cash and assets from ConocoPhillips and DEFS. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction, as previously announced, was anticipated to include ConocoPhillips’ interest in the Empress System gas processing and natural gas liquids marketing business (Empress System). However, the transfer of the Empress System to Duke Energy was delayed pending damage repairs to the assets from a recent windstorm and as a result ConocoPhillips has transferred an equivalent value of cash to Duke Energy in July 2005. The Empress System was subsequently transferred to Duke Energy in August 2005 and cash of approximately $230 million was remitted to ConocoPhillips as consideration for the transfer. Subsequent to the DEFS disposition transaction, DEFS will no longer be consolidated into Duke Energy’s historical consolidated financial statements and will be accounted for by Duke Energy as an equity method investment. See Note 13 for the impacts of this transaction on certain cash flow hedges. The DEFS Canadian natural gas gathering and processing facilities and the Empress System will be included in Duke Energy’s Natural Gas Transmission business unit.

• DENA asset sales during the six month period ended June 30, 2005 totaled approximately $34 million in proceeds. Those sales resulted in pre-tax gains of $27 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Total sales were driven principally by the sale of Grays Harbor to an affiliate of Invenergy LLC resulting in a pre-tax gain of approximately $21 million (excluding any potential contingent consideration), which was completed in the first quarter of 2005.

• Additional asset and business sales during the six month period ended June 30, 2005 totaled approximately $20 million in proceeds. These sales resulted in net pre-tax gains of $6 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations.

For the three months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $26 million of proceeds and $12 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. For the six months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $77 million of proceeds and $54 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 “legacy” land sales.

For the three months ended June 30, 2004, the sale of other assets resulted in approximately $39 million in proceeds, and net losses of $11 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. For the six months ended June 30, 2004, the sale of other assets resulted in approximately $142 million in proceeds, and net losses of $349 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. Significant sales of other assets and equity investments during the six months ended June 30, 2004 are as follows:

• 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

14

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

these assets of approximately $360 million in the first quarter of 2004, which represented the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in (Losses) Gains on Sale of Other Assets, net in the first quarter of 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.

• 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 (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations.

• In May 2004, Duke Energy reached an agreement to sell its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V, (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico for approximately $60 million. Duke Energy recorded a $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statement of Operations, related to a note receivable from Cantarell, in the first quarter of 2004 in anticipation of this sale. The sale closed in the third quarter of 2004.

For the three months ended June 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $136 million of proceeds and $62 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. For the six months ended June 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $303 million of proceeds, and $121 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Significant sales included the Potomac Yard retail center in the Washington, D.C. area in March 2004, the Alexandria land tract in the Washington, D.C. area in June 2004 and several large “legacy” land sales closed in the first quarter of 2004.

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 June 30, 2005, there are no significant remaining amounts to be paid under these severance plans. Provision for severance is included in Operation, Maintenance and Other in the Consolidated Statements of Operations.

15

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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)
			Net Operating Income									Net Gain on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			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 June 30, 2005
DENA	$	23	$	(4	)	$	(2	)	$	(2	)	$	—	$	—	$	—
International Energy		—		2			2			—			—		—		—
Total consolidated	$	23	$	(2	)	$	—		$	(2	)	$	—	$	—	$	—
Three Months Ended June 30, 2004
Field Services	$	15	$	(1	)	$	(1	)	$	—		$	—	$	—	$	—
DENA		58		(2	)		(1	)		(1	)		—		—		—
International Energy		17		(2	)		2			(4	)		39		9		30
Other		1		2			1			1			—		—		—
Total consolidated	$	91	$	(3	)	$	1		$	(4	)	$	39	$	9	$	30
Six Months Ended June 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—	$	—	$	—
DENA		57		(4	)		(2	)		(2	)		—		—		—
International Energy		—		4			3			1			—		—		—
Total consolidated	$	61	$	—		$	1		$	(1	)	$	—	$	—	$	—
Six Months Ended June 30, 2004
Field Services	$	51	$	1		$	—		$	1		$	2	$	1	$	1
DENA		58		(2	)		(1	)		(1	)		—		—		—
International Energy		82		3			1			2			295		27		268
Other		1		2			1			1			—		—		—
Total consolidated	$	192	$	4		$	1		$	3		$	297	$	28	$	269

16

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 June 30, 2005 and December 31, 2004.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale

	June 30, 2005		December 31, 2004
	(in millions)
Current assets	$	15	$	40
Investments and other assets		30		12
Net property, plant and equipment		33		72
Total assets held for sale	$	78	$	124
Current liabilities	$	—	$	30
Long-term debt		14		14
Total liabilities associated with assets held for sale	$	14	$	44

Field Services

In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, Duke Energy’s Field Services business unit 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.

DENA

On September 21, 2004, DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving would purchase DENA’s 75% interest in Bayside Power L.P. (Bayside). As a result of the above agreement, DENA presented the $54 million of assets and $14 million of liabilities as of June 30, 2005 and $59 million of assets and $19 million of liabilities as of December 31, 2004 related to Bayside as Assets Held For Sale in the Consolidated Balance Sheets. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was approximately $20 million at June 30, 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. The sale of Bayside closed on July 13, 2005. The after-tax gain on this sale will be included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations in the third quarter of 2005.

17

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

International Energy

In order to eliminate exposure to international markets outside of Latin America and Canada, Duke Energy’s International Energy business unit 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 cost 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.

In the second quarter of 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion. This resulted in recording an additional $40 million after-tax gain in the second quarter of 2004. The after-tax gain was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific Business.

In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $57 million as of June 30, 2005 and $68 million as of December 31, 2004. This receivable is included in Receivables in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004. During the three months ended June 30, 2004, International Energy recorded a $14 million (approximately $9 million after tax) allowance for the note based on management’s assessment of the probability of not collecting the entire note. The after-tax loss was included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations.

The results of operations related to these operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. In the case Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the projects as “discontinued operations” as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. In the second quarter of 2005, Crescent classified two commercial properties with a fair value less cost to sell of approximately $24 million as Assets Held for Sale in the Consolidated Balance Sheets.

Other

During 2003, Duke Energy decided to exit the merchant finance business conducted by Duke Capital Partners (DCP). The sale or collection of all of DCP’s notes receivable was completed during 2004. DCP’s operating results are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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.”

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

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.

During the first quarter of 2005, Duke Energy discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 13 for further discussion.

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

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Three Months Ended June 30, 2005
Franchised Electric	$	1,229	$	5		$	1,234		$	274
Natural Gas Transmission		691		58			749			302
Field Services		2,888		—			2,888			166
DENA		443		20			463			(56	)
International Energy		182		—			182			86
Crescent		112		—			112			39
Total reportable segments		5,545		83			5,628			811
Other		109		40			149			(88	)
Eliminations		—		(123	)		(123	)		—
Interest expense		—		—			—			(297	)
Interest income and other (a)		—		—			—			36
Total consolidated	$	5,654	$	—		$	5,654		$	462
Three Months Ended June 30, 2004
Franchised Electric	$	1,222	$	6		$	1,228		$	338
Natural Gas Transmission		635		53			688			311
Field Services		2,338		3			2,341			95
DENA		621		25			646			(38	)
International Energy		147		—			147			68
Crescent		101		—			101			87
Total reportable segments		5,064		87			5,151			861
Other		252		38			290			(26	)
Eliminations		—		(125	)		(125	)		—
Interest expense		—		—			—			(336	)
Interest income and other (a)		—		—			—			41
Total consolidated	$	5,316	$	—		$	5,316		$	540

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

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Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Six Months Ended June 30, 2005
Franchised Electric	$	2,489	$	10		$	2,499		$	610
Natural Gas Transmission		1,814		110			1,924			709
Field Services		5,459		103			5,562			1,087
DENA		899		32			931			(91	)
International Energy		350		—			350			154
Crescent		176		—			176			91
Total reportable segments		11,187		255			11,442			2,560
Other		216		(27	)		189			(257	)
Eliminations		—		(228	)		(228	)		—
Interest expense		—		—			—			(590	)
Interest income and other (a)		—		—			—			63
Total consolidated	$	11,403	$	—		$	11,403		$	1,776
Six Months Ended June 30, 2004
Franchised Electric	$	2,488	$	11		$	2,499		$	762
Natural Gas Transmission		1,617		109			1,726			709
Field Services		4,633		61			4,694			186
DENA		1,217		53			1,270			(595	)
International Energy		301		—			301			97
Crescent		139		—			139			147
Total reportable segments		10,395		234			10,629			1,306
Other		557		77			634			(31	)
Eliminations		—		(311	)		(311	)		—
Interest expense		—		—			—			(692	)
Interest income and other (a)		—		—			—			55
Total consolidated	$	10,952	$	—		$	10,952		$	638

(a) 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

	June 30, 2005			December 31, 2004
	(in millions)
Franchised Electric	$	18,066		$	18,199
Natural Gas Transmission		17,079			17,106
Field Services		7,523			6,810
DENA		7,020			6,737
International Energy		3,576			3,329
Crescent		1,478			1,315
Total reportable segments		54,742			53,496
Other		1,505			1,829
Reclassifications and eliminations (a)		(252	)		145
Total consolidated assets	$	55,995		$	55,470

(a) 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 $4,106 million as of June 30, 2005 and $4,148 million as of December 31, 2004, with $3,343 million allocated to Natural Gas Transmission, $496 million to Field Services, $260 million to International Energy and $7 million to Crescent as of June 30, 2005. The $42 million decrease from December 31, 2004 to June 30, 2005 was related solely to foreign currency exchange rate fluctuations of $55 million at Natural Gas Transmission and $2 million at Field Services, partially offset by an increase of $15 million at International Energy.

13. Risk Management Instruments

The following table shows the carrying value of Duke Energy’s derivative portfolio as of June 30, 2005, and December 31, 2004.

Derivative Portfolio Carrying Value

	June 30, 2005			December 31, 2004
	(in millions)
Hedging	$	1,294		$	795
Trading		(7	)		18
Undesignated		(353	)		(262	)
Total	$	934		$	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 $94 million as of June 30, 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 $499 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 $91 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 transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see Note 9), 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. As a result, approximately $120 million of unrealized pre-tax losses previously recorded in

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AOCI related to these contracts has been recognized in earnings by Duke Energy in the six months ended June 30, 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 $20 million and $130 million of additional realized and 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 and six months ended June 30, 2005, respectively. 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 June 30, 2005 and December 31, 2004 are collateral assets of approximately $636 million and $300 million, respectively, which represents cash collateral posted by Duke Energy with other third parties. This increase in cash collateral posted by Duke Energy is primarily due to increases in crude oil prices as well as increases to the forward market prices of power. Included in Other Current Liabilities in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are collateral liabilities of approximately $533 million and $523 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.

As of June 30, 2005, $436 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 $11 and $30 million in the three and six months ended June 30, 2005, respectively, as compared to a gain of $3 and $5 million in the three and six months ended June 30, 2004, respectively.

14. Regulatory Matters

Merger with Cinergy. As discussed in Note 9, on May 9, 2005, Duke Energy and Cinergy announced they have entered into a definitive merger agreement. Approval of the merger by several federal and state agencies is required. During the second quarter of 2005, Duke Energy and Cinergy filed petitions or applications for approval of the merger with the Indiana Utility Regulatory Commission and the Public Utilities Commission of Ohio. In July 2005, Duke Energy and Cinergy filed an application for approval of the merger with the Federal Energy Regulatory Commission (FERC), and Duke Energy filed applications for the approval of the merger with the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC). In August 2005, Duke Energy and Cinergy filed an application for the approval of the merger with the Kentucky Public Service Commission. During the third quarter of 2005, Duke Energy and Cinergy expect to file the remaining required petitions or applications for approval or pre-approval of the merger.

Franchised Electric. Rate Related Information. NCUC and PSCSC approve rates for retail electric sales within their states. 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). 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

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billion be amortized within the rate freeze period (2002 to 2007). Franchised Electric’s amortization expense related to this clean air legislation totals $482 million from inception, with $156 million recorded for the first six months of 2005 and $33 million recorded for the first six months of 2004. As of June 30, 2005, cumulative expenditures totaled $249 million, with $125 million incurred for the first six months of 2005 and $21 million incurred for the first six months of 2004, and are included in Net Cash Provided by (Used in) Investing Activities on the Consolidated Statements of Cash Flows. Duke Energy has changed the classification of these expenditures for clean air legislation from cash flows used in operating activities to cash flows used in investing activities, as discussed in Note 1. 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 of $200 million from previous estimates of approximately $1.5 billion.

Depreciation and Decommissioning Studies. In March 2005, Duke Power Company (Duke Power) filed the results of a depreciation rate study with the NCUC and the 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. A NCUC decision on the appropriate level of decommissioning funding was received in July 2005 at the requested $48 million annual amount.

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 requested approval in the fuel case proceeding to flow to customers approximately $100 million in revenue requirement for previously recorded excess deferred tax liabilities that are recorded as regulatory liabilities in the form of a rate decrement. On June 15, 2005, the NCUC approved Duke Power’s proposed fuel rate and deferred tax decrement. Duke Power proposed a similar action to the PSCSC in its fuel rate adjustment filing in July 2005 for the South Carolina portion of approximately $40 million.

Market-Based Rate Authority. FERC has instituted a rulemaking process to modify its methodology to assess generation market power. In the interim, FERC has established certain market screens. Failure to satisfy any of those screens requires an applicant for market-based rates to submit additional tests and information to FERC to demonstrate that it does not have generation market power in the region in which it fails the screens. Some of the screens which do not subtract obligations to serve native load are difficult for a franchised utility such as Duke Power to pass. In an order issued on June 30, 2005, the FERC revoked the authority for Duke Power to make wholesale power sales within its control area at market-based rates based on the FERC’s determination that Duke Power fails one of the applicable market screens. Under the FERC’s order, Duke Power must pay partial refunds and may prospectively make wholesale power sales within its control area only at cost-based rates. The FERC’s order is not expected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position. Pursuant to a previous order, Duke Power may continue to make wholesale sales at market-based rates to customers outside of its control area.

Duke Power “Independent Entity” to Perform Transmission Functions. On July 22, 2005 Duke Power filed a plan with the FERC seeking approval to establish an “Independent Entity” (IE) to serve as a coordinator of certain transmission functions and an “Independent Monitor” (IM) to monitor the transparency and fairness of the operation of Duke Power’s transmission system. Under the proposal, Duke Power will remain the owner and operator of the transmission system with responsibility for the provision of transmission service under Duke Power’s Open Access Transmission Tariff. Duke Power has retained (subject to FERC approval) the Midwest Independent Transmission System Operator, Inc. to act as the IE and Potomac Economics, Ltd. to act as the IM. Duke Power is seeking approval of the proposal by early 2006. Duke Power is not at this time seeking adjustments to its transmission rates to reflect the incremental cost of the proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

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Natural Gas Transmission. FERC Accounting Order. In June 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order is effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and is expected to increase annual expenses within Natural Gas Transmission by approximately $15 million to $20 million. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule are not impacted.

Rate Related Information. In December 2004, the Ontario Energy Board (OEB) approved the 2005 rates for 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. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $8 million during the six months ended June 30, 2005.

The OEB also directed Union Gas to provide direction as to how it will proceed with setting 2006 rates, including the use of an earnings sharing mechanism. Union Gas responded to this directive by recommending the use of the same earnings sharing mechanism as found appropriate by the Board for 2005 rates, with a request for a rate increase. The OEB indicated in May 2005 that it was prepared to consider Union Gas’ request, but required an application and supporting evidence, which Union Gas provided to the OEB on July 29, 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 June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement has been filed with FERC for its review and approval. FERC is expected to act on the settlement agreement prior to the end 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 groundwater 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

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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 U. S. Environmental Protection Agency’s (EPA’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 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. The EPA’s final Clean Air Mercury Rule (CAMR) was published in the Federal Register May 18, 2005. 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. The EPA’s final Clean Air Interstate Rule (CAIR) was published in the Federal Register May 12, 2005. 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 in 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. On July 11, 2005, Duke Energy and others filed petitions with the U.S. Court of Appeals for the District of Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy is seeking to have the EPA revise the method of allocating SO₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $65 million as of June 30, 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

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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 appealed the case to the U.S. Fourth Circuit Court of Appeals. On June 15, 2005, the Fourth Circuit ruled in favor of Duke Energy and effectively adopted Duke Energy’s view that permitting of projects is not required unless the work performed implicates a net increase in the hourly rate of emissions. The EPA has filed a petition for rehearing with the Fourth Circuit, and may seek further appellate review. Based on the current rulings, 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 courts could significantly affect the outcome.

Western Energy Litigation. Since 2000, plaintiffs have filed 48 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 these dismissed suits appealed, 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 petitioned the U.S. Supreme Court for certiorari and the Court invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted. On May 27, 2005, the U.S. Solicitor General recommended that certiorari be denied. On June 27, 2005, the U.S. Supreme Court denied certiorari.

• 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 was 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. On July 22, 2005, the Superior Court for San Diego County entered an order granting preliminary approval of the class-action settlement and authorizing notice of the proposed settlements to be sent to the respective class members. A hearing on final approval of the class-action settlements is presently scheduled for December 2005.

• 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

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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 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 Mercantile 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 to date 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 included 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 did 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 was approved by the SEC in July 2005.

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

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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.

In July 2005, a plaintiff indicated that it intends to file suit in the Kansas State District Court against Duke Energy and DETM, as well as other energy companies, claiming that it was harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and by entering into unlawful arrangements and agreements. The plaintiff claims the defendants violated Kansas’ antitrust laws. The plantiff did not specify the amount of plaintiff’s purported damages. No lawsuit on this matter has been filed as of the date of this Form 10-Q. Duke Energy cannot predict the outcome of this matter at this time.

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

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ExxonMobil’s claims. ExxonMobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. The arbitration panel has scheduled briefing on the reconsideration motion and postponed the commencement date of the arbitration hearing from January 2006 to October 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, originally scheduled to commence in August 2005 in Calgary, Canada, has tentatively been rescheduled for March 2006. 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 Investments and Other 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.

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 June 30, 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 June 30, 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 June 30, 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 three successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of June 30, 2005, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and an initial segment of the first option phase covering mission reactor modifications.

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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 June 30, 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 Duke Power, has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of June 30, 2005, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.

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

• DCS will exercise its options under the Duke Power Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract, which, in turn, will depend on whether the U.S. Congress will authorize funding for DCS 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 has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of June 30, 2005 was approximately $800 million. Of this amount, approximately $400 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 2007 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.

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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 June 30, 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 June 30, 2005 was approximately $500 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities. Of those letters of credit, approximately $225 million expire in 2005, with the remainder expiring in 2006.

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 June 30, 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 of June 30, 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. Of those guarantees, approximately $5 million expire in 2005, with the remainder expiring in 2006 and 2007.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Capital 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 Capital 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 Capital 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

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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 June 30, 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 June 30, 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 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 resulted in a decrease of $12 million for the year ended December 31, 2004 and will result in a decrease of $12 million for the year ended December 31, 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 Issue 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 EITF 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 EITF Issue No. 04-8 was effective for fiscal years ended after December 15, 2004 and has been applied retroactively

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Notes To Consolidated Financial Statements—(Continued)

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 ongoing entity. The consensus in EITF 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 June 30, 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.

Duke Energy currently has retirement eligible employees with outstanding share-based payment awards. Compensation cost related to those awards is currently recognized over the stated vesting period or until actual retirement occurs. Upon adoption of SFAS No. 123R, Duke Energy will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

The impact on EPS for the three and six month periods ended June 30, 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

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Notes To Consolidated Financial Statements—(Continued)

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 share-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 earnings 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.

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 to 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 six months of 2005, Duke Energy recognized a benefit of approximately $3 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 the 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

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

liability of $45 million as of December 31, 2004. During the second quarter of 2005, Duke Energy reorganized various entities which enabled the company to reduce the $45 million tax liability to $41 million. No extraordinary dividends were repatriated during the six months ended June 30, 2005. Duke Energy repatriated approximately $200 million of extraordinary dividends in July 2005.

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes have been made for potential liabilities resulting from these matters. As of June 30, 2005, Duke Energy had total provisions of approximately $144 million for uncertain tax positions, as compared to $149 million as of December 31, 2004, including 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

The Energy Policy Act of 2005 became law in August 2005 and addresses a wide span of issues. The legislation directs specified agencies to conduct a significant number of studies on various sectors of the energy industry. In addition, many of the provisions will require these agencies to develop rules and procedures for their application. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA), establishes a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear plants, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission, improves the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. The enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 9.

For information on subsequent events related to acquisitions and dispositions, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and income taxes, see Notes 9, 11, 14, 15 and 18.

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

INTRODUCTION

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

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.

RESULTS OF OPERATIONS

Results of Operations and Variances

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	5,654		$	5,316		$	338		$	11,403		$	10,952		$	451
Operating expenses		4,915			4,537			378			10,021			9,462			559
Gains on sales of investments in commercial and multi-family real estate		12			62			(50	)		54			121			(67	)
(Losses) gains on sales of other assets, net		—			(11	)		11			33			(349	)		382
Operating income		751			830			(79	)		1,469			1,262			207
Other income and expenses, net		85			89			(4	)		1,390			149			1,241
Interest expense		297			336			(39	)		590			692			(102	)
Minority interest expense		77			43			34			493			81			412
Earnings from continuing operations before income taxes		462			540			(78	)		1,776			638			1,138
Income tax expense from continuing operations		151			134			17			598			167			431
Income from continuing operations		311			406			(95	)		1,178			471			707
(Loss) income from discontinued operations, net of tax		(2	)		26			(28	)		(1	)		272			(273	)
Net income		309			432			(123	)		1,177			743			434
Dividends and premiums on redemption of preferred and preference stock		2			3			(1	)		4			5			(1	)
Earnings available for common stockholders	$	307		$	429		$	(122	)	$	1,173		$	738		$	435

Overview of Drivers and Variances

Three Months Ended June 30, 2005 as Compared to June 30, 2004. For the three months ended June 30, 2005, earnings available for common stockholders were $307 million, or $0.33 per basic share and $0.32 per diluted share. For the three months ended June 30, 2004, earnings available for common stockholders were $429 million, or $0.46 per basic share and $0.45 per diluted share. Significant items that contributed to decreased earnings available for common stockholders for the quarter included:

• A $130 million pre-tax gain (net of minority interest of $5 million) recorded in 2004 related to the settlement of the Enron bankruptcy proceedings

• An approximate $60 million pre-tax decrease in earnings at Franchised Electric due primarily to the impacts of milder weather and increased operating and maintenance costs, partially offset by increased sales to wholesale customers and the impact of continued growth in customers and improved economic conditions

• A $45 million pre-tax gain at Crescent Resources LLC (Crescent) in the second quarter 2004 on the sale of the Alexandria tract in the Washington D.C. area

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• A $28 million after-tax decrease from discontinued operations driven primarily by a $40 million after-tax gain recorded in the second quarter 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 $9 million after-tax charge on its European gas trading and marketing business (the European Business)

• A $24 million pre-tax charge to increase liabilities associated with mutual insurance companies recorded in the second quarter 2005, and

• A $17 million increase in income tax expense from continuing operations, resulting primarily from a release of various income tax reserves in the second quarter 2004 totaling approximately $52 million, partially offset by lower income from continuing operations in 2005.

Partially offsetting these amounts were:

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• An approximate $70 million pre-tax increase in earnings (net of minority interest of $25 million) at Field Services due primarily to the favorable effects of commodity prices, net of hedging, excluding the impact of those hedges which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of Duke Energy Field Services, LLC (DEFS) by Duke Energy, and

• A $39 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. For the six months ended June 30, 2005, earnings available for common stockholders were $1,173 million, or $1.25 per basic share and $1.20 per diluted share. For the six months ended June 30, 2004, earnings available for common stockholders were $738 million, or $0.80 per basic share and $0.78 per diluted share. Significant items that contributed to increased earnings available for common stockholders for the six months included:

• An $802 million pre-tax gain (net of minority interest of $343 million) recorded in 2005 on the sale of DEFS’s 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 (U.S.); and certain other power and gas contracts (collectively, the Southeast Plants)

• An approximate $120 million pre-tax increase in earnings (net of minority interest of $50 million) at Field Services due primarily to the favorable effects of commodity prices, net of hedging, excluding the impact of those hedges which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy

• An approximate $120 million pre-tax increase in earnings (net of minority interest of $15 million) at DENA due primarily to lower operating and general and administrative expenses, and the absence of mark-to-market losses associated with the disqualified hedge positions in 2004, partially offset by lower power generation sales as a result of milder weather in the western U.S. region and lower margins resulting from the current weakness in the natural gas transportation and marketing business

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• A $102 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004

• An approximate $100 million pre-tax gain recorded in the first quarter 2005 on the sale of Duke Energy’s limited partner interest in TEPPCO LP

• An approximate $60 million pre-tax increase in earnings (net of minority interest of $1 million) at International Energy due primarily to the higher volumes and favorable foreign currency exchange rate change in Brazil and higher product margins at National Methanol Company, and

• An approximate $21 million pre-tax gain recorded in the first quarter 2005 on the sale of DENA’s partially completed Grays Harbor power plant (Grays Harbor) in Washington state.

Partially offsetting these amounts were:

• A $431 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, discussed above, and the release of various income tax reserves in the second quarter 2004 totaling approximately $52 million

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• A $273 million after-tax decrease in income from discontinued operations driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business, partially offset by a $9 million after-tax charge on its European Business

• An approximate $250 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”)

• An approximate $150 million pre-tax decrease in earnings at Franchised Electric due primarily to the impacts of milder weather and increased operating and maintenance costs

• A $130 million pre-tax gain (net of minority interest of $5 million) recorded in 2004 related to the settlement of the Enron bankruptcy proceedings

• An approximate $50 million pre-tax charge to increase liabilities associated with mutual insurance companies, and

• A $45 million pre-tax gain at Crescent in the second quarter 2004 on the sale of the Alexandria tract in the Washington D.C. area.

On a consolidated and a segment reporting basis, results of operations through June 30, 2005, may not be indicative of the full year.

Consolidated Operating Revenues

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating revenues for the three months ended June 30, 2005 increased $338 million, compared to the same period in 2004. This change was driven primarily by:

• A $547 million increase at Field Services due primarily to higher average commodity prices, primarily natural gas liquids (NGL) and natural gas, in the second quarter 2005

• A $61 million increase at Natural Gas Transmission due primarily to favorable foreign exchange rates as a result of the strengthening Canadian dollar and higher natural gas prices that are passed through to customers (mostly offset by gas price and currency impacts to expenses), and

• An approximate $45 million increase due principally to higher energy prices and volumes at International Energy and higher residential developed lot sales at Crescent.

Partially offsetting these increases in revenues were:

• A $131 million decrease in revenue as a result of the continued wind-down of Duke Energy Merchants LLC (DEM)

• A $94 million decrease in natural gas sales revenues at DENA due primarily to lower natural gas sales volumes as a result of the continued wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with ExxonMobil Corporation) operations, partially offset by higher average natural gas prices in the second quarter 2005

• A $77 million decrease at DENA due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, and

• A $22 million decrease in DENA’s net trading margin due primarily to the absence of mark-to-market gains associated with the disqualified hedge positions in the second quarter 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating revenues for the six months ended June 30, 2005 increased $451 million, compared to the same period in 2004. This change was driven primarily by:

• A $868 million increase at Field Services due primarily to higher average commodity prices, primarily NGL and natural gas, in 2005

• A $198 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)

• A $68 million increase in DENA’s net trading margin due primarily to the absence of mark-to-market losses associated with the disqualified hedge positions in 2004

• A $49 million increase at International Energy due primarily to higher energy prices and volumes, and

• A $37 million increase at Crescent due primarily to higher residential developed lot sales.

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Partially offsetting these increases in revenues were:

• A $328 million decrease in revenue as a result of the continued wind-down of DEM

• A $296 million decrease in natural gas sales revenues at DENA due primarily to lower natural gas sales volumes as a result of the continued wind-down of DETM operations, partially offset by higher average natural gas prices in 2005

• An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, 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”), and

• A $123 million decrease at DENA due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather.

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

Consolidated Operating Expenses

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating expenses for the three months ended June 30, 2005 increased $378 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $500 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

• A $135 million pre-tax gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings, and

• A $63 million increase in operating expenses at Franchised Electric due primarily to increased planned outage costs at generating plants and increased fuel expenses, due primarily to higher coal costs, partially offset by decreased purchased power expenses as a result of lower retail demand due primarily to milder weather.

Partially offsetting these increases in expenses were:

• A $131 million decrease due to the continued wind-down of DEM

• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement

• An $87 million decrease in plant fuel costs and operations, maintenance and depreciation expenses at DENA due primarily to the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather, and

• A $56 million reduction in natural gas purchases at DENA due primarily to the continued wind-down of DETM, partially offset by higher average natural gas prices in 2005.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating expenses for the six months ended June 30, 2005 increased $559 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $900 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

• A $143 million increase in operating expenses at Franchised Electric due primarily to increased planned outage and maintenance costs at fossil and nuclear generating plants, increased fuel expenses, due primarily to higher coal costs, and increased regulatory amortization

• A $135 million pre-tax gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings

• 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 approximate $50 million increase in liabilities associated with mutual insurance companies.

Partially offsetting these increases in expenses were:

• A $332 million decrease due to the continued wind-down of DEM

• A $249 million reduction in natural gas purchases at DENA due primarily to the continued wind-down of DETM, partially offset by higher average natural gas prices in 2005

• A $195 million decrease in plant fuel costs and operations, maintenance and depreciation expenses at DENA due primarily to the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather, and

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• A $105 million pre-tax charge recorded in 2004 related to the California and western U.S. energy markets settlement.

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

Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated gains on sales of investments in commercial and multi-family real estate for the three months ended June 30, 2005 decreased $50 million, compared to the same period in 2004 primarily as a result of the 2004 gain on sale of the Alexandria tract in the Washington, DC area.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated gains on sales of investments in commercial and multi-family real estate for the six months ended June 30, 2005 decreased $67 million, compared to the same period in 2004 primarily as a result of the 2004 gain on sale of the Alexandria tract and a commercial project in the Washington, DC area.

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

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (losses) gains on sales of other assets, net for the three months ended June 30, 2005 increased $11 million, compared to the same period in 2004. The increase was due primarily to 2004 pre-tax losses at DENA related to the liquidation of contractual positions in connection with the continued wind down of DETM’s operations.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (losses) gains on sales of other assets, net for the six months ended June 30, 2005 increased $382 million, compared to the same period in 2004. The increase was due primarily to the charge in the first quarter 2004 associated with the sale of DENA’s Southeast Plants and the first quarter 2005 gain on the sale of DENA’s Grays Harbor power plant in Washington state.

Consolidated Operating Income

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating income for the three months ended June 30, 2005 decreased $79 million, compared to the same period in 2004. Decreased operating income was due primarily to the gain recorded in the second quarter 2004 related to the settlement of the Enron bankruptcy proceedings, unfavorable results at Franchised Electric due primarily to milder weather and increased operating and maintenance expenses, the gain on sale of the Alexandria tract in the Washington D.C. area in the second quarter 2004, unfavorable results at DENA due primarily to lower net trading margins and lower margins from the natural gas transportation and marketing business, and an increase in liabilities associated with mutual insurance companies recorded in the second quarter 2005, partially offset by a charge related to the California and western U.S. energy markets settlement in the second quarter 2004 and favorable results at Field Services driven primarily by favorable effects of commodity prices net of hedging.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating income for the six months ended June 30, 2005 increased $207 million, compared to the same period in 2004. Increased operating income was due primarily to a loss in 2004 related to the sale of DENA’s Southeast Plants, a charge in 2004 related to the California and western U.S. energy markets settlement, favorable results at Field Services driven primarily by favorable effects of commodity prices, net of hedging, favorable results at DENA due primarily to higher net trading margins and lower operating expenses, mainly resulting from the sale of the Southeast Plants, and favorable results at International Energy driven primarily by higher volumes and favorable foreign currency exchange rate changes, partially offset by charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, unfavorable results at Franchised Electric due primarily to increased operating and maintenance expenses and milder weather in 2005, the gain recorded in 2004 related to the settlement of the Enron bankruptcy proceedings and the gain on sale of the Alexandria tract in the Washington D.C. area in the second quarter 2004.

Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses, net

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated other income and expenses, net for the three months ended June 30, 2005 was relatively flat, compared to the same period in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated other income and expenses, net for the six months ended June 30, 2005 increased approximately $1.2 billion, compared to the same period in 2004. The increase was due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP.

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Consolidated Interest Expense

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated interest expense for the three months ended June 30, 2005 decreased $39 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated interest expense for the six months ended June 30, 2005 decreased $102 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004.

Consolidated Minority Interest Expense

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated minority interest expense for the three months ended June 30, 2005 increased $34 million, compared to the same period in 2004 driven primarily by increased earnings from DEFS as a result of higher commodity prices.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated minority interest expense for the six months ended June 30, 2005 increased $412 million, compared to the same period in 2004 driven primarily by increased earnings at DEFS as a result of the sale of TEPPCO GP and higher commodity prices.

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated income tax expense from continuing operations for the three months ended June 30, 2005 increased $17 million, compared to the same period in 2004. The increase primarily resulted from a release of various income tax reserves in the second quarter 2004, partially offset by lower income from continuing operations in 2005.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated income tax expense from continuing operations for the six months ended June 30, 2005 increased $431 million, compared to the same period in 2004. The increase primarily resulted from higher earnings, primarily as a result of higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and the release of various income tax reserves in the second quarter 2004.

Consolidated (Loss) Income from Discontinued Operations, net of tax

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (loss) income from discontinued operations, net of tax for the three months ended June 30, 2005 decreased $28 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business, offset by an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (loss) income from discontinued operations, net of tax for the six months ended June 30, 2005 decreased $273 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in 2004 related to the sale of the Asia-Pacific Business, offset by an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business.

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, 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.

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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

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Franchised Electric	$	274		$	338		$	610		$	762
Natural Gas Transmission		302			311			709			709
Field Services		166			95			1,087			186
DENA		(56	)		(38	)		(91	)		(595	)
International Energy		86			68			154			97
Crescent		39			87			91			147
Total reportable segment EBIT		811			861			2,560			1,306
Other		(88	)		(26	)		(257	)		(31	)
Interest expense		(297	)		(336	)		(590	)		(692	)
Interest income and other (a)		36			41			63			55
Consolidated earnings from continuing operations before income taxes	$	462		$	540		$	1,776		$	638

(a) 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.

Franchised Electric

	Three Months Ended June 30,								Six Months Ended June 30,
	2005			2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	1,234		$	1,228	$	6		$	2,499	$	2,499	$	—
Operating expenses		959			896		63			1,890		1,747		143
Gains on sales of other assets, net		—			3		(3	)		1		3		(2	)
Operating income		275			335		(60	)		610		755		(145	)
Other (expense) income, net		(1	)		3		(4	)		—		7		(7	)
EBIT	$	274		$	338	$	(64	)	$	610	$	762	$	(152	)
Sales, Gigawatt-hours (GWh)		20,431			20,087		344			41,594		42,050		(456	)

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

Increase (decrease) over prior year	Three Months Ended June 30, 2005		Six Months Ended June 30, 2005
Residential sales (a)	(9.1	)%	(4.9	)%
General service sales (a)	(4.3	)%	(1.5	)%
Industrial sales (a)	(1.2	)%	2.1	%
Wholesale sales	100.2	%	4.6	%
Total Franchised Electric sales	1.7	%	(1.1	)%
Average number of customers	1.9	%	2.0	%

(a) Major components of Franchised Electric’s retail sales

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $32 million increase in wholesale power revenues, due primarily to higher sales volumes resulting from strong demand coupled with better generation availability in 2005. Milder weather reduced retail demand within the Franchised Electric service territory, resulting in more generation availability for wholesale sales outside the Franchised Electric service territory. Hotter weather in areas outside the service territory drove increased demand for energy

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• A $17 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Franchised Electric’s service territory and improving economic conditions in North Carolina and South Carolina. The number of customers in 2005 has increased by approximately 40,000 compared to the same period in 2004

• A $15 million increase in fuel revenues, driven by increased fuel rates for retail customers due primarily to increased coal costs and increased Megawatt-hour (MWh) sales to wholesale customers. The delivered cost of coal in 2005 is approximately $9 per ton higher than the same period in 2004. Wholesale MWh sales increased by approximately 100% compared to the same period resulting in significantly more fuel revenue collections from those customers

• A $2 million increase related to industrial customers in North Carolina due to the Bulk Power Marketing (BPM) profit sharing agreement entered into in June 2004. During second quarter 2005, sharing of profits was $12 million, while during second quarter 2004, sharing of profits was $14 million. Sharing of profits in North Carolina in second quarter 2004 was due to cumulative BPM profits during the six months ended June 30, 2004, as the sharing agreement was approved in June 2004 but applied to earnings since January 1, 2004, while sharing of profits in second quarter 2005 was due to BPM profits during the three months ended June 30, 2005, partially offset by

• A $59 million decrease in GWh sales to retail customers due to milder weather during the quarter. Weather statistics were 24% below normal in second quarter 2005 compared to 23% above normal during the same period in 2004.

Operating Expenses. The increase was driven primarily by:

• Increased operating and maintenance expenses of $48 million, due primarily to increased planned power plant outages during the second quarter, increased right of way maintenance expenses and higher storm costs

• Increased fuel expenses of $32 million, due primarily to increased coal costs. Generation fueled by coal accounted for more than 50% of total generation during the second quarter of both 2005 and 2004 and the delivered cost of coal in 2005 is approximately $9 per ton higher than the same period in 2004

• Increased depreciation expense of $9 million, due primarily to additional capital spending and assets placed in service, partially offset by

• Decreased purchased power expenses of $23 million, due primarily to milder weather which resulted in lower retail demand in the Franchised Electric service territory and therefore lower need for purchased power, and

• An $8 million reduction related to sharing of profits from BPM sales with charitable, educational and economic development programs in North Carolina and South Carolina. During second quarter 2005, donations were $5 million, while donations were $13 million in second quarter 2004. Second quarter 2004 donations consist of cumulative BPM profits during the six months ended June 30, 2004, as the sharing agreement was approved in June 2004 but applied to earnings since January 1, 2004, while second quarter 2005 donations consist of BPM profits during the three months ended June 30, 2005.

EBIT. The decrease was due primarily to mild weather and increased operating and maintenance expenses. These changes were partially offset by increased wholesale power results and the impact of continued growth in the number of residential and general service customers and improved economic conditions in North Carolina and South Carolina.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. Operating revenues were consistent due primarily to:

• A $31 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Franchised Electric’s service territory and improving economic conditions in North Carolina and South Carolina. The number of customers in 2005 has increased by approximately 40,000 compared to the same period in 2004

• A $27 million increase in wholesale power revenues, due primarily to higher market prices and increased sales volumes. Market prices are up approximately 20% over the same period in 2004 and sales volumes increased due to milder weather which reduced retail demand within the Franchised Electric service territory, resulting in more generation availability for wholesale sales outside the Franchised Electric service territory

• A $22 million increase in fuel revenues, driven by increased fuel rates for retail customers due primarily to increased coal costs and increased MWH sales to wholesale customers. The delivered cost of coal in 2005 is approximately $8 per ton higher than the same period in 2004. Wholesale MWH sales increased by approximately 5% compared to the same period resulting in increased fuel revenue collections from those customers, partially offset by

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PART I

• A $78 million decrease in GWh sales to retail customers due to milder weather. Weather statistics for both the heating and cooling periods in 2005 were unfavorable compared to the same periods in 2004.

Operating Expenses. The increase was driven primarily by:

• Increased operating and maintenance expenses of $79 million, due primarily to increased planned outage and maintenance at generating plants, increased planned maintenance to improve the reliability of distribution and transmission equipment and increased right of way maintenance expenses

• Increased fuel expenses of $39 million, due primarily to increased coal costs. Generation fueled by coal accounted for more than 50% of total generation during both periods and the delivered cost of coal in 2005 is approximately $8 per ton higher than the same period in 2004

• Increased regulatory amortization of $17 million, due primarily to increased amortization of compliance costs related to clean air legislation passed by North Carolina in 2002. 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 by December 31, 2007. Regulatory amortization expenses were approximately $156 million for the six months ended June 30, 2005 as compared to $139 million during the same period in 2004, and

• Increased depreciation expense of $15 million, due primarily to additional capital spending and assets placed in service.

EBIT. The decrease was due primarily to increased operating and maintenance expenses, milder weather and increased regulatory amortization. These changes were partially offset by increased sales to wholesale customers and the impact of continued growth in the number of residential and general service customers and improved economic conditions in North Carolina and South Carolina.

Matters Impacting Future Franchised Electric Results

Franchised Electric’s annual EBIT growth rate over the next three years is expected to be in the zero to two percent range. Franchised Electric expects segment EBIT for 2005 to be at or slightly below 2004 segment EBIT of $1,467 million.

Natural Gas Transmission

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	749	$	688	$	61		$	1,924	$	1,726	$	198
Operating expenses		457		397		60			1,233		1,035		198
Gains on sales of other assets, net		2		9		(7	)		4		9		(5	)
Operating income		294		300		(6	)		695		700		(5	)
Other income, net of expenses		14		13		1			28		19		9
Minority interest expense		6		2		4			14		10		4
EBIT	$	302	$	311	$	(9	)	$	709	$	709	$	—
Proportional throughput, TBtu (a)		719		726		(7	)		1,775		1,815		(40	)

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations, since revenues are primarily composed of demand charges.

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $36 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)

• An $8 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, and

• A $4 million increase from completed and operational pipeline expansion projects in the United States.

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Operating Expenses. The increase was driven primarily by:

• A $27 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

• A $17 million increase related to the 2004 resolution of ad valorem tax issues in various states, and

• An $8 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

EBIT. The decrease in EBIT was due primarily to the 2004 resolution of ad valorem tax issues, partially offset by earnings from expansion projects and favorable foreign exchange rate changes from the strengthening Canadian currency.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $105 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a markup at Union Gas. This revenue increase is offset in expenses

• A $93 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $10 million increase 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 $105 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $71 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above), and

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

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.

EBIT. EBIT remained constant driven by increased earnings from expansion projects and favorable foreign exchange rate changes from the strengthening Canadian dollar offset by lower revenues at Union Gas due to the new earnings-sharing mechanism and the 2004 resolution of ad valorem tax issues.

Field Services

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,888	$	2,341	$	547		$	5,562	$	4,694	$	868
Operating expenses		2,651		2,209		442			5,237		4,437		800
Gains on sales of other assets, net		—		—		—			2		—		2
Operating income		237		132		105			327		257		70
Other income, net of expenses		7		15		(8	)		1,258		33		1,225
Minority interest expense		78		52		26			498		104		394
EBIT	$	166	$	95	$	71		$	1,087	$	186	$	901
Natural gas gathered and processed/transported, TBtu/d (a)		7.3		7.4		(0.1	)		7.2		7.3		(0.1	)
NGL production, MBbl/d (b)		370		368		2			367		360		7
Average natural gas price per MMBtu (c), (d), (e)	$	6.73	$	5.99	$	0.74		$	6.50	$	5.84	$	0.66
Average NGL price per gallon (d) (e)	$	0.75	$	0.61	$	0.14		$	0.74	$	0.60	$	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.

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PART I

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $250 million increase due to a $0.14 per gallon increase in average NGL prices

• A $210 million increase due to a $0.74 per MMBtu increase in average natural gas prices

• A $34 million increase attributable to the impact of cash flow hedging, which reduced revenues by approximately $14 million for the three months ended June 30, 2005 and by approximately $48 million for the same period in 2004. As a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, approximately $20 million of mark-to-market losses on these hedges for the three months ended June 30, 2005 have been presented in Other, as discussed below

• A $25 million increase attributable to higher natural gas sales volumes, partially offset by lower NGL sales volumes

• A $20 million increase attributable to a $14.85 per-barrel increase in average crude oil prices to $53.17 during the three months ended June 30, 2005 from $38.32 during the same period in 2004, and

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

Operating Expenses. The increase was due primarily to:

• A $395 million increase due to higher average costs of raw natural gas supply due primarily to an increase in average NGL and natural gas prices

• A $20 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds, and for outside consulting fees

• A $15 million increase attributable to higher purchased raw natural gas supply, and

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

Other Income, net of expenses. The decrease was due primarily to:

• A $10 million decrease in earnings from equity method investments, primarily as a result of the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the sale of Duke Energy’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to increased earnings from DEFS.

EBIT. The increase was driven primarily by the favorable effects of commodity price increases.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was due primarily to:

• A $400 million increase due to a $0.14 per gallon increase in average NGL prices

• A $325 million increase due to a $0.66 per MMBtu increase in average natural gas prices

• A $53 million increase attributable to the impact of cash flow hedging, which reduced revenues by approximately $41 million for the six months ended June 30, 2005 and by approximately $94 million for the same period in 2004. As a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, approximately $130 million of mark-to-market losses on these hedges for the six months ended June 30, 2005 have been presented in Other, as discussed below

• A $45 million increase attributable to a $14.90 per-barrel increase in average crude oil prices to $51.64 during the six months ended June 30, 2005 from $36.74 during the same period in 2004

• A $25 million increase in wholesale propane marketing activity primarily due to higher propane prices

• A $10 million increase attributable to higher natural gas volumes, partially offset by lower NGL sales volumes, and

• An $8 million increase attributable to higher transportation, storage and processing fees, primarily due to higher fees from processing contracts.

Operating Expenses. The increase was due primarily to:

• A $605 million increase due to higher average costs of raw natural gas supply, 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 during the first quarter as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were

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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 $35 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds and for outside consulting fees

• A $20 million increase in wholesale propane marketing activity primarily due to higher propane prices, and

• A $10 million increase attributable to higher purchased raw natural gas supply.

Other Income, net of expenses. The increase was due primarily to:

• An approximate $1.1 billion 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 $100 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. The gain was partially offset by

• A $16 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS due to commodity price increases. The overall increase was not proportionate to the increase in Field Services’ earnings during the six months ended June 30, 2005, 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 prior to the discontinuance of cash flow hedges during the first quarter of 2005, as discussed above.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP 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 Field Services during the six months ended June 30, 2005.

Matters Impacting Future Field Services Results

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. The DEFS disposition transaction involves DEFS transferring its Canadian assets to Duke Energy’s Natural Gas Transmission business unit as well as Duke Energy receiving cash from ConocoPhillips. The DEFS disposition transaction is estimated to result in a pre-tax gain to Field Services of approximately $600 million. Duke Energy will deconsolidate its investment in DEFS in July 2005, subsequent to the closing of the DEFS disposition transaction. For further information see Duke Capital’s Current Report on Form 8-K dated July 11, 2005 which contains pro-forma information regarding the impact of the DEFS disposition transaction as if it occurred on January 1, 2004 for purposes of the pro-forma statement of operations and March 31, 2005 for the pro-forma balance sheet. Future Field Services results are subject to volatility for factors such as commodity price changes.

DENA

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	463		$	646		$	(183	)	$	931		$	1,270		$	(339	)
Operating expenses		525			674			(149	)		1,063			1,515			(452	)
(Losses) Gains on sales of other assets, net		(1	)		(16	)		15			27			(368	)		395
Operating loss		(63	)		(44	)		(19	)		(105	)		(613	)		508
Other income (loss), net of expenses		3			—			3			4			(2	)		6
Minority interest benefit		(4	)		(6	)		2			(10	)		(20	)		10
EBIT	$	(56	)	$	(38	)	$	(18	)	$	(91	)	$	(595	)	$	504
Actual plant production, GWh (a)		3,939			5,422			(1,483	)		7,895			10,883			(2,988	)
Proportional megawatt capacity in operation (a)											9,890			15,465			(5,575	)

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

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Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $94 million decrease due primarily to a $144 million reduction from lower natural gas sales volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $50 million from higher average natural gas prices

• A $77 million decrease due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, and

• A $22 million decrease in net trading margin due primarily to the absence of mark-to-market gains associated with the disqualified hedge positions in 2004.

Operating Expenses. The decrease was driven primarily by:

• A $105 million decrease due to the absence of a 2004 charge related to the California and western U.S. energy markets settlement in June 2004

• A $65 million reduction in plant fuel costs, due primarily to lower volumes resulting from the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather. Also contributing to the decrease was a favorable impact from natural gas hedging activities

• A $56 million decrease due primarily to a $141 million reduction from lower natural gas purchase volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $85 million from higher average natural gas prices

• A $22 million reduction in operations, maintenance and depreciation expenses, due primarily to the sales of the Southeast Plants and partially completed western U.S. plants in 2004

• A $15 million decrease in general and administrative expenses, due primarily to headcount reductions, lower fees related to letters of credit, and reserve reductions, partially offset by

• A $113 million ($108 million net of minority interest expense) increase due to the absence of a 2004 gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Losses on Sales of Other Assets, net. The increase was due primarily to 2004 pre-tax losses of $16 million ($10 million net of minority interest expense) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations.

Minority Interest Benefit. The decreased benefit was due primarily to reduced losses at DETM as a result of the continued wind-down of DETM operations.

EBIT. The decrease was due primarily to reduced power generation sales as a result of milder weather in the western U.S. region, lower margins resulting from the current weakness in the natural gas transportation and marketing business, and the absence of prior year mark-to-market gains on disqualified hedge positions. These decreases were partially offset by lower operating and general and administrative expenses, and the absence of prior year losses on asset sales.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $296 million decrease due primarily to a $396 million reduction from lower natural gas sales volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $100 million from higher average natural gas prices

• A $123 million decrease due primarily to lower power generation volumes resulting from the sale of the Southeast Plants in 2004 and reduced run times in the western U.S. region, mainly as a result of milder weather, partially offset by

• A $68 million increase in net trading margin due primarily to the absence of mark-to-market losses associated with the disqualified hedge positions in 2004.

Operating Expenses. The decrease was driven primarily by:

• A $249 million decrease due primarily to a $401 million reduction from lower natural gas purchase volumes related to the continued wind down of DETM’s operations. This decrease was partially offset by an increase of approximately $152 million from higher average natural gas prices

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• A $140 million reduction in plant fuel costs, due primarily to lower volumes resulting from the sale of the Southeast Plants in 2004 and lower run times in the western U.S. region, mainly as a result of milder weather. Also contributing to the decrease was a favorable impact from natural gas hedging activities

• A $105 million decrease due to the absence of a 2004 charge related to the California and western U.S. energy markets settlement in June 2004

• A $55 million reduction in operations, maintenance and depreciation expenses, due primarily to the sales of the Southeast Plants and partially completed western U.S. plants in 2004

• A $26 million decrease in general and administrative expenses, due primarily to headcount reductions, lower fees related to letters of credit, and reserve releases, partially offset by

• A $113 million ($108 million net of minority interest expense) increase due to the absence of a 2004 gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Gains (Losses) on Sales of Other Assets, net. The increase was due primarily to the absence of approximately $360 million in 2004 pre-tax losses associated with the sale of the Southeast Plants and $14 million ($8 million net of minority interest expense) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations. Also contributing to the increase was a pre-tax gain of approximately $21 million associated with the sale of the Grays Harbor power plant in Washington State in 2005 (see Note 9 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Minority Interest Benefit. The decrease was due primarily to reduced losses at DETM as a result of the continued wind-down of DETM operations.

EBIT. The increase was due primarily to the gains on asset sales in 2005, the absence of 2004 losses associated with the Southeast Plants, higher net trading margins and lower operating and general and administrative expenses. These increases were partially offset by lower margins resulting from the current weakness in the natural gas transportation and marketing business and reduced power generation sales as a result of milder weather in the western U.S. region.

Matters Impacting Future DENA Results

Duke Energy believes merchant energy will play a vital role in meeting the United States’ energy demand. One of Duke Energy’s stated objectives for 2005 is to position DENA to be a successful merchant operator. On May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they have entered into a definitive merger agreement, which contemplates that DENA will transfer its five midwest generation assets, with total property, plant and equipment balances of approximately $1.7 billion and net assets of approximately $1.5 billion as of June 30, 2005, to Cincinnati, Gas & Electric Company, a wholly-owned subsidiary of Cinergy. This transfer is not expected to have a material impact on DENA’s future results of operations (see Note 9 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Duke Energy also continues to pursue other options to further strengthen DENA’s business model. Depending on the options selected, there is a risk that material impairments or other charges or credits could be recorded, including the potential disqualification of certain contracts as hedges and the recognition of an approximate $1.4 billion unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption as of June 30, 2005. 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 $1.2 billion as of June 30, 2005. These amounts exclude obligations attributable to DENA’s gas transportation and structured power portfolio. (For further information, see Item 7 “Contractual Obligations” disclosure in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004). The timing of recognition of any loss on the normal purchases and normal sales contracts and the recognition of any unrealized net gains on DENA cash flow hedge positions may or may not occur in the same period, depending upon the options selected.

For 2005, DENA expects to significantly reduce its EBIT loss through additional cost savings and higher gross margins. DENA’s marketing efforts in 2005 will focus on contracting capacity and energy production from its plants. DENA’s future results of operations may not realize the full impact of commodity market price changes as certain of DENA’s future generation sales volumes and fuel purchases are contracted under fixed price arrangements.

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International Energy

	Three Months Ended June 30,						Six Months Ended June 30,
	2005		2004		Increase (Decrease)		2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	182	$	147	$	35	$	350	$	301	$	49
Operating expenses		127		98		29		246		229		17
Operating income		55		49		6		104		72		32
Other income, net of expenses		34		22		12		55		31		24
Minority interest expense		3		3		—		5		6		(1	)
EBIT	$	86	$	68	$	18	$	154	$	97	$	57
Sales, GWh		4,527		4,247		280		9,062		8,811		251
Proportional megawatt capacity in operation								4,139		4,130		9

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $13 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $7 million increase in Guatemala mainly due to higher energy prices

• A $6 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices, and

• A $5 million increase in Argentina primarily due to higher volumes and higher prices.

Operating Expenses. The increase was driven primarily by:

• A $12 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• An $11 million increase in Guatemala mainly due to higher fuel prices, maintenance expense and a bad debt reversal in 2004, and

• An $8 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes.

Other Income, net of expenses. The increase was driven primarily by a $9 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $14 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $10 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices

• A $10 million increase in Guatemala mainly due to higher energy prices, and

• A $7 million increase in Argentina due primarily to higher volumes and higher prices.

Operating Expenses. The increase was driven primarily by:

• A $14 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• A $13 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes, partially offset by

• A $13 million decrease related to a 2004 charge for the planned disposition of the ownership share in Compãnia de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004.

Other Income, net of expenses. The increase was driven primarily by a $16 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

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EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador and a $13 million charge associated with the planned disposition of the ownership share in Cantarell recorded in 2004.

Crescent

	Three Months Ended June 30,								Six Months Ended June 30,
	2005			2004		Increase (Decrease)			2005			2004		Increase (Decrease)
	(in millions)
Operating revenues	$	112		$	101	$	11		$	176		$	139	$	37
Operating expenses		79			75		4			130			111		19
Gains on sales of investments in commercial and multi-family real estate		12			62		(50	)		54			121		(67	)
Operating income		45			88		(43	)		100			149		(49	)
Other expense, net		(1	)		—		(1	)		(1	)		—		(1	)
Minority interest expense		5			1		4			8			2		6
EBIT	$	39		$	87	$	(48	)	$	91		$	147	$	(56	)

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was due primarily to a $14 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida offset by a $2 million decrease in residential club operations.

Operating Expenses. The increase was due primarily to a $7 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $2 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was due primarily to a $49 million decrease in real estate land sales resulting from large land sales in 2004 ($45 million gain from the sale of the Alexandria tract in the Washington, D.C. area in June of 2004) as compared to minimal land sales in the second quarter of 2005.

EBIT. The decrease was due primarily to the reduction in real estate land sales as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by a $42 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida.

Operating Expenses. The increase was driven primarily by a $24 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $3 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

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

• A $49 million decrease in real estate land sales primarily due to the $45 million sale of the Alexandria tract in the Washington, D.C. area in June of 2004 as compared to minimal real estate land sales in the first half of 2005, and

• A $19 million decrease in commercial project sales due to the sale of a commercial project in the Washington, D.C. area in March of 2004 as compared to minimal project sales in the first half of 2005.

EBIT. The decrease was due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in the first half of 2004 as compared to minimal project and real estate land sales in the first half of 2005, partially offset by an increase in residential developed lot sales.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, D.C. area which resulted in higher than normal gains during 2004. Crescent expects segment EBIT from continuing operations and discontinued operations in 2005 to be at, or above segment EBIT from continuing operations and discontinued operations of approximately

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$250 million in 2004. When property management or other significant continuing involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

Other

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	149		$	290		$	(141	)	$	189		$	634		$	(445	)
Operating expenses		241			311			(70	)		451			698			(247	)
(Loss) Gains on sales of other assets, net		—			(7	)		7			—			7			(7	)
Operating loss		(92	)		(28	)		(64	)		(262	)		(57	)		(205	)
Other income, net of expenses		4			2			2			5			26			(21	)
EBIT	$	(88	)	$	(26	)	$	(62	)	$	(257	)	$	(31	)	$	(226	)

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $131 million decrease in revenue as a result of the continued wind-down of DEM, and

• An approximate $20 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 $131 million decrease as a result of the continued wind-down of DEM, partially offset by

• A $24 million charge to increase liabilities associated with mutual insurance companies, and

• A $21 million reduction in operating expenses in 2004 at DEM, as a result of a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

(Loss) Gains on Sales of Other Assets, net. Gains on sales of other assets for the three months ended June 30, 2005 changed primarily due to a $7 million loss on the sale of an aircraft in 2004.

EBIT. 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, an increase in liabilities associated with mutual insurance companies and the 2004 gain related to the settlement of the Enron bankruptcy proceedings, as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $328 million decrease in revenues as a result of the continued wind-down of DEM, and

• An approximate $130 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 $332 million decrease as a result of the continued wind-down of DEM, partially offset by

• An approximate $50 million charge to increase liabilities associated with mutual insurance companies, and

• A $21 million reduction in operating expenses in 2004 at DEM as a result of a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

(Losses) Gains on Sales of Other Assets, net. The decrease was driven primarily by:

• A $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad) in 2004, partially offset by

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• A $7 million loss on the sale of an aircraft in 2004.

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

• A $17 million decrease in equity earnings from Duke/Fluor Daniel (D/FD) as a result of the wind-down of the partnership, and

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

EBIT. 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, an increase in liabilities associated with mutual insurance companies, the 2004 gain related to the settlement of the Enron bankruptcy proceedings, and the decrease in equity earnings from D/FD, as discussed above.

Matters Impacting Future Other Results

Future Other results will be subject to volatility as a result of the changes in the mark-to-market of certain Field Services commodity price risk contracts subsequent to the discontinuance of hedge accounting in first quarter 2005. The fair value of these contracts as of June 30, 2005 was a liability of approximately $225 million, and approximately $120 million of this value is attributable to contracts which will settle in 2005. As these contracts settle Duke Energy will realize an offset to revenues at Field Services.

Other Impacts on Earnings Available for Common Stockholders

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $39 million, due primarily to Duke Energy’s debt reduction efforts in 2004.

Minority Interest Expense. Minority interest expense increased by $34 million driven primarily by increased earnings from DEFS, as a result of higher commodity prices.

Income Tax Expense from Continuing Operations. The effective tax rate for the three months ended June 30, 2005 was 33%, compared to 25% for the same period in 2004. The increase in the effective tax rate was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004. The impact of this prior-year release of income tax reserves was offset by lower pretax earnings during the three months ended June 30, 2005, compared to the same period in 2004.

(Loss) Income from Discontinued Operations, net of tax. The $28 million decrease was driven primarily by a $40 million after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business. This gain was partially offset by a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $102 million, due primarily to Duke Energy’s debt reduction efforts in 2004.

Minority Interest Expense. Minority interest expense increased $412 million, driven primarily by increased earnings at DEFS, as a result of the sale of TEPPCO GP and higher commodity prices.

Income Tax Expense from Continuing Operations. The effective tax rate for the six months ended June 30, 2005 was 34%, compared to 26% for same period in 2004. The increase was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004. Additionally, the increase in income tax expense from continuing operations is a result of higher pretax 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.

(Loss) Income from Discontinued Operations, net of tax. The $273 million decrease was driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business. This gain was partially offset by a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $377 million for the six months ended June 30, 2005, compared to the same period in 2004 due to approximately $300 million of additional collateral posted by Duke Energy during 2005 attributable to increased

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crude oil prices, as well as increases to the forward market prices of power, offset by approximately $100 million of additional collateral posted by Duke Energy in 2004, and a tax refund received in 2004 due to a taxable loss in 2003. These decreases in cash provided by operating activities were partially offset by an increase in cash collected from receivables at DENA and DEFS in 2005.

Investing Cash Flows

Net cash provided by (used in) investing activities increased approximately $1.7 billion for the six months ended June 30, 2005 as compared to the same period in 2004. This increase was principally driven by the approximate $1.3 billion in proceeds on sales of equity investments and other assets in 2005, primarily due to the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP for approximately $1.2 billion, offset by the approximate $700 million in proceeds received in 2004 primarily as a result of the sale of the Asia-Pacific business, the sale of turbines and excess equipment, and the sale of Field Services’ assets. Additionally, approximately $70 million of the increase in investing activities is due to reduced capital and investment expenditures during 2005. Additionally, during 2004, an additional amount of cash of approximately $1 billion was invested in short-term investments as a result of the 2004 disposition transactions and increased operating cash flows, as discussed above, which resulted in excess cash balances being invested in these short-term investments.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased approximately $1.5 billion for the six months ended June 30, 2005, compared to same period in 2004. This change was due primarily to the 2005 repurchase of 32.6 million shares of common stock for $909 million, including approximately $10 million in commissions and other fees (see Note 3 to the Consolidated Financial Statements, “Common Stock”), and lower proceeds from common stock issuances during 2005 driven by the $875 million settlement of the forward purchase contract component of Duke Energy’s Equity Units in 2004. This was partially offset by approximately $340 million of higher redemptions and net paydowns of long-term debt, commercial paper, notes payable, and preferred stock of a subsidiary during 2004.

The fixed charges coverage ratio, calculated using Securities and Exchange Commission (SEC) guidelines, was 4.5 times for the six months ended June 30, 2005 and 1.9 times for the six months ended June 30, 2004.

Cash generated from operations, the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, and the DEFS disposition transaction 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 of approximately $2.0 billion as of June 30, 2005, along with 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 needs of shareholders and the long-term financial strength of Duke Energy.

Significant Financing Activities. In December 2004, Duke Energy reached an agreement to sell its Grays Harbor 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 first quarter of 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.

In connection with the up to $2.5 billion share repurchase program announced in February 2005, Duke Energy entered into an accelerated share repurchase transaction. 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”). 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 June 30, 2005, Duke Energy had repurchased 2.6 million shares of its common stock through the separate open-market purchase plan at a weighted average price of $28.97 per share. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment.

On June 29, 2005, Duke Energy declared a quarterly cash dividend on its common stock of $0.31 per share, an increase of $0.035 cents per share above its previous level. The dividend is payable on September 16, 2005, to shareholders of record at the close of business on August 12, 2005.

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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 June 30, 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 and its subsidiaries, with the exception of Maritimes & Northeast Pipeline LLC and Maritimes & Northeast LP, 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 August 5, 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.

Credit Ratings Summary as of August 5, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy (a)	BBB	Baa1	Not applicable
Duke Capital LLC (a)	BBB-	Baa3	Not applicable
Duke Energy Field Services (a)	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP (a)	BBB	Baa2	Not applicable
Westcoast Energy Inc.	BBB	Not applicable	A(low)
Union Gas Limited (a)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC (b)	A	A2	A
Maritimes & Northeast Pipeline, LP (b)	A	A2	A
Duke Energy Trading and Marketing, LLC (c)	BBB-	Not applicable	Not applicable

(a) Represents senior unsecured credit rating

(b) Represents senior secured credit rating

(c) Represents corporate credit rating

In May 2005, following the announcement of Duke Energy’s merger with Cinergy, Standard & Poor’s Ratings Service placed the ratings of Duke Energy and its subsidiaries (excluding DEFS, Maritimes & Northeast Pipeline LLC and Maritimes & Northeast Pipeline LP) on “CreditWatch with negative implications.” In addition, Moody’s Investors Service revised the ratings outlook of Duke Energy, Duke Capital and Texas Eastern Transmission LP to “Developing” and Dominion Bond Rating Service placed the credit ratings of Westcoast Energy Inc. “Under Review with Developing Implications.”

In August 2005, Moody’s Investors Service downgraded the credit rating of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP from A1 to A2. Moody’s actions were primarily a result of their concerns over downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. Moody’s concluded their action placing the ratings outlook for both companies to “stable”.

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, while 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. In addition, the completion of the merger with Cinergy and the resulting corporate structure could impact the credit ratings of Duke Energy or its subsidiaries.

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 United States 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, which 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 June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $150 million. Additionally, as a result of DETM’s credit rating as of June 30, 2005, Duke Capital could be

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required to segregate up to approximately $260 million of cash collateral held by Duke Capital. 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 June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $290 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate swap and foreign exchange agreements may require settlement payments due to termination of the agreements. As of June 30, 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.

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 June 30, 2005, Duke Energy and its subsidiaries had effective 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 as compared to December 31, 2004, resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of June 30, 2005, Duke Energy had access to 900 million Canadian dollars (approximately U.S. $732 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 six months 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

Merger with Cinergy. On May 9, 2005, Duke Energy and Cinergy announced they have 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 June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. 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, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $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 the approval of shareholders of both companies and a number of federal and state governmental authorities. (For further discussion of the status of regulatory filings see Note 14 to the Consolidated Financial Statements, “Regulatory Matters”.) The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their

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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.

Although Duke Energy and Cinergy believe that the expectation as to timing for the closing of the merger described above is reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all required approvals will be received.

Further information concerning the structure and details of the proposed merger is set forth in Duke Energy’s Current Report on Form 8-K dated May 9, 2005, which includes as exhibits the merger agreement and a joint press release of Duke Energy and Cinergy announcing the execution of the merger agreement. In connection with the merger, a registration statement on Form S-4 has been filed with the SEC by Duke Energy Holding Corp. (Registration No. 333-126318), containing a preliminary joint proxy statement/prospectus.

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. The Canadian government’s strategy for achieving its Kyoto reduction target includes, among other things, a proposal for an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (LFE). Consultations to develop plan details for the LFE program are under way. A draft LFE rule could be issued in the fall of 2005 and finalized in the spring of 2006. 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 enacting either state-specific or 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.

That Duke Energy will be proactive in climate change policy debate in the United States does not change the uncertainty around 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 either nation’s greenhouse gas policy 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 for its business operations in the United States and Canada if 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 June 30, 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

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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.

Duke Energy currently has retirement eligible employees with outstanding share-based payment awards. Compensation cost related to those awards is currently recognized over the stated vesting period or until actual retirement occurs. Upon adoption of SFAS No. 123R, Duke Energy will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

The impact on Earnings Per Share (EPS) for the three and six month periods ended June 30, 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 share-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 earnings 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.

Subsequent Events

The Energy Policy Act of 2005 became law in August 2005 and addresses a wide span of issues. The legislation directs specified agencies to conduct a significant number of studies on various sectors of the energy industry. In addition, many of the provisions will require these agencies to develop rules and procedures for their application. Among the key provisions, the Energy Policy Act of 2005

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repeals the Public Utility Holding Company Act (PUHCA), establishes a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear plants, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission, improves the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. The enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 9 to the Consolidated Financial Statements, “Acquisitions and Dispositions.”

For information on subsequent events related to acquisitions and dispositions, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and income taxes see Notes 9, 11, 14 15 and 18 to the Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

For an in-depth discussion of Duke Energy’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Energy’s Annual Report on Form 10-K 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 $1.4 billion as of June 30, 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 $1.2 billion as June 30, 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 charges or credits 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. These amounts exclude obligations attributable to DENA’s gas transportation and structured power portfolio. For further information, see Item 7 “Contractual Obligations” disclosure in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. The timing of recognition of any loss on the normal purchases and normal sales contracts and the recognition of any unrealized net gains on DENA cash flow hedge positions may or may not occur in the same period, depending upon the options selected.

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.

Daily Earnings at Risk (in millions)

	June 30, 2005 One-Day Impact on Operating Income for 2005 (a)		Estimated Average One-Day Impact on Operating Income for Second Quarter 2005 (a)		Estimated Average One-Day Impact on Operating Income for the Year 2004 (a)		High One-Day Impact on Operating Income for Second Quarter 2005 (a)		Low One-Day Impact on Operating Income for Second Quarter 2005 (a)
Calculated DER	$	3	$	4	$	16	$	6	$	3

(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.

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

Credit Risk

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments due to IDC. In 2000, Duke Hidalgo was sold to Calpine Corporation and Duke Capital remained responsible for the lease guaranty obligations. Calpine Corporation has indemnified Duke Capital’s lease guaranty obligations. Total maximum exposure under this guarantee obligation as of June 30, 2005 is approximately $200 million.

Item 4. Controls and Procedures.

Duke Energy’s management, including the Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Duke Energy’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. Duke Energy’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in Duke Energy’s reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Because of Duke Energy’s ongoing evaluation of internal controls over financial reporting, management continues to implement procedures and controls to enhance the reliability of Duke Energy’s internal control procedures including planned improvements in our financial closing and consolidation processes. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2005 that have materially affected, or are reasonably likely to materially affect, Duke Energy’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For information regarding legal proceedings that became reportable events or in which there were material developments in the second quarter of 2005, see Note 14 to the Consolidated Financial Statements, “Regulatory Matters” and Note 15 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities for Second Quarter of 2005

Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (a)	Approximate Dollar Value of Shares (or Units) that May Yet Be Purchased Under Plans or Programs (b) (in billions)
April 1 to April 30	1,600,000	$	28.80	1,600,000	$	1.6
May 1 to May 31	1,000,000	$	29.24	1,000,000	$	1.6
June 1 to June 30	—		—	—	$	1.6

(a) Shares purchased in accordance with Duke Energy’s open market purchase plan (see Note 3 to the Consolidated Financial Statements, “Common Stock”).

(b) Duke Energy has announced plans to execute up to approximately $2.5 billion in common stock repurchases over the next three years. During second quarter 2005, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment (see Note 3 to the Consolidated Financial Statements, “Common Stock”).

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

At the Duke Energy Corporation Annual Meeting of Shareholders on May 12, 2005, shareholders elected Roger Agnelli, G. Alex Bernhardt Sr., and Dennis R. Hendrix to serve as Class II directors, and A. Max Lennon to serve as a Class III director. These and all other members of the Board of Directors continuing in office have tendered a letter of resignation effective as of the 2006 annual meeting, so that the terms of all directors will end at that meeting and all directors shall thereafter be elected annually. Below is a tabulation of votes with respect to each nominee for director at the meeting:

Nominee	For	Against/Withheld
Roger Agnelli	731,336,467	5,300,601
G. Alex Bernhardt, Sr.	728,633,231	8,003,837
Dennis R. Hendrix	731,622,874	5,014,194
A. Max Lennon	728,233,751	8,403,317

Class I directors whose terms continued after the meeting are Paul M. Anderson, Ann Maynard Gray, Michael E.J. Phelps and James T. Rhodes. Class III directors whose terms continued after the meeting are William T. Esrey Jr. and James G. Martin.

The following paragraphs provide voting results for the two other matters submitted to a shareholder vote at the annual meeting:

With respect to the proposal to approve amendments to Duke Energy’s Restated Articles of Incorporation to eliminate classification of Duke Energy’s Board of Directors, 726,351,856 shares voted for the proposal, 7,057,966 shares voted against the proposal and 3,227,246 shares abstained.

With respect to the proposal to ratify the selection of Deloitte & Touche LLP to act as independent auditors to make examination of Duke Energy’s accounts for the year 2005, 727,105,998 shares voted for the proposal, 7,969,448 shares voted against the proposal and 1,562,022 shares abstained.

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Item 6. Exhibits.

    (a) Exhibits

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

Exhibit Number
2.1	Agreement and Plan of Merger, dated May 8, 2005, by and among the registrant, Cinergy Corp., Deer Holding Corporation, Deer Acquisition Corp., and Cougar Acquisition Corp. (filed in Form 8-K of the registrant, May 9, 2005, File No. 1-4928, as Exhibit 2.1)
*2.1.1	Amendment No. 1 to the Agreement and Plan of Merger, dated July 11, 2005, by and among the registrant, Cinergy Corp., Duke Energy Holding Corp., Deer Acquisition Corp., and Cougar Acquisition Corp.
3.1	Restated Articles of Incorporation of registrant, dated June 18, 1997 (filed with Form S-8 of the registrant, No. 333-29563, effective June 19, 1997, as Exhibit 4(G))
3.1.1	Articles of Amendment to Restated Articles of Incorporation of registrant, dated February 9, 1999 (filed with Form 8-K of the registrant on February 11, 1999, File No. 1-4928, as Exhibit A to Exhibit 4.1)
3.1.2	Articles of Amendment to Restated Articles of Incorporation of registrant, dated April 28, 1999 (filed with Form S-3 of the registrant, file number 333-81573, filed June 25, 1999 as Exhibit 4(B))
3.1.3	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 2, 2001 (filed with Post-Effective Amendment No. 2 to Form S-3 of the registrant, file number 333-81573, filed December 12, 2001, as Exhibit 4(B) -1)
3.1.4	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 1, 2002 (filed with Form 10-Q of the registrant for the quarter ended March 31, 2002, File No. 1-4928, as Exhibit 3)
*3.1.5	Articles of Amendment to Restated Articles of Incorporation of registrant, dated May 12, 2005
*3.2	By-Laws of registrant, as amended and restated May 12, 2005
4.1	Amendment No. 1, dated as of May 8, 2005, to the Rights Agreement, dated as of December 17, 1998, between the registrant and The Bank of New York, as rights agent (filed in Form 8-K of the registrant, May 12, 2005, File No. 1-4928, as Exhibit 4.1)
*10.1	$500,000,000 Amended and Restated Credit Agreement dated as of June 30, 2005, among the registrant, the banks listed therein, Citibank N.A., as Administrative Agent, and Bank of America, N.A., as Syndication Agent
*10.2	$600,000,000 Amended and Restated Credit Agreement dated as of June 30, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent
*10.3	$800,000,000 364-Day Credit Agreement dated as of June 29, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank, PLC, as Syndication Agent
*10.4	Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of May 26, 2005
*10.4.1	First Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of June 30, 2005
*10.4.2	Second Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of July 11, 2005
*10.5**	Resolution of Board of Directors, May 12, 2005, Approving Change to Retainer and Attendance Fees for Non-Employee Directors
*10.6**	Form of Phantom Stock Award Agreement dated as of May 11, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and Jimmy W. Mogg

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Exhibit Number
10.7**	Form of Phantom Stock Award Agreement dated as of May 12, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and nonemployee directors (filed in Form 8-K of the registrant, May 17, 2005, File No. 1-4928, as Exhibit 10.1)
*31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.

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SIGNATURES

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

	DUKE ENERGY CORPORATION
Date: August 9, 2005	/S/    DAVID L. HAUSER
	David L. Hauser Group Vice President and Chief Financial Officer
Date: August 9, 2005	/S/    STEVEN K. YOUNG
	Steven K. Young Vice President and Controller

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