Duke Energy Carolinas 10-Q 2005 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For quarter ended September 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. Yesx No¨

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

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

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 November 4, 2005…927,566,970

INDEX

DUKE ENERGY CORPORATION

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

Item		Page
PART I. FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004	1
	CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2005 AND DECEMBER 31, 2004	2
	CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004	4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	5
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64
4.	CONTROLS AND PROCEDURES	66
PART II. OTHER INFORMATION
1.	LEGAL PROCEEDINGS	67
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	67
6.	EXHIBITS	68
	SIGNATURES	69

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, including the economic, operational and other effects of Hurricanes Katrina and Rita

• 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 or other external factors over which Duke Energy has no control

• Changes in environmental and other laws and regulations to which Duke Energy and its subsidiaries are subject

• 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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	671		$	3,060		$	6,877		$	8,804
Regulated electric		1,614			1,413			4,099			3,899
Regulated natural gas and natural gas liquids		743			608			2,654			2,304
Total operating revenues		3,028			5,081			13,630			15,007
Operating Expenses
Natural gas and petroleum products purchased		316			2,417			5,679			7,316
Operation, maintenance and other		777			778			2,479			2,261
Fuel used in electric generation and purchased power		488			394			1,229			1,277
Depreciation and amortization		406			500			1,349			1,303
Property and other taxes		134			125			432			388
Impairment and other charges		17			22			140			22
Total operating expenses		2,138			4,236			11,308			12,567
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		63			28			117			149
Gains (Losses) on Sales of Other Assets, net		580			(3	)		589			(353	)
Operating Income		1,533			870			3,028			2,236
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		176			33			256			110
(Losses) Gains on sales and impairments of equity investments		(20	)		(14	)		1,225			(14	)
Other income and expenses, net		(40	)		30			19			112
Total other income and expenses		116			49			1,500			208
Interest Expense		228			329			813			984
Minority Interest Expense		10			62			508			146
Earnings From Continuing Operations Before Income Taxes		1,411			528			3,207			1,314
Income Tax Expense from Continuing Operations		487			147			1,095			365
Income From Continuing Operations		924			381			2,112			949
Discontinued Operations
Net operating (loss) income, net of tax		(550	)		9			(584	)		(83	)
Net (loss) gain on dispositions, net of tax		(333	)		(1	)		(310	)		266
(Loss) Income From Discontinued Operations		(883	)		8			(894	)		183
Net Income		41			389			1,218			1,132
Dividends and Premiums on Redemption of Preferred and Preference Stock		3			2			7			7
Earnings Available For Common Stockholders	$	38		$	387		$	1,211		$	1,125
Common Stock Data
Weighted-average shares outstanding
Basic		926			938			936			925
Diluted		964			973			973			960
Earnings per share (from continuing operations)
Basic	$	0.99		$	0.40		$	2.25		$	1.02
Diluted	$	0.96		$	0.39		$	2.17		$	0.99
(Loss) Earnings per share (from discontinued operations)
Basic	$	(0.95	)	$	0.01		$	(0.96	)	$	0.20
Diluted	$	(0.92	)	$	0.01		$	(0.92	)	$	0.19
Earnings per share
Basic	$	0.04		$	0.41		$	1.29		$	1.22
Diluted	$	0.04		$	0.40		$	1.25		$	1.18
Dividends per share	$	—		$	—		$	0.860		$	0.825

See Notes to Consolidated Financial Statements

1

PART I

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(Unaudited)

(In millions)

	September 30,		December 31,
	2005		2004
ASSETS
Current Assets
Cash and cash equivalents	$	377	$	533
Short-term investments		1,062		1,319
Receivables (net of allowance for doubtful accounts of $128 at September 30, 2005 and $135 at December 31, 2004)		2,131		3,237
Inventory		879		942
Assets held for sale		1,579		40
Unrealized gains on mark-to-market and hedging transactions		129		962
Other		1,952		938
Total current assets		8,109		7,971
Investments and Other Assets
Investments in unconsolidated affiliates		2,474		1,292
Nuclear decommissioning trust funds		1,473		1,374
Goodwill		3,773		4,148
Notes receivable		179		232
Unrealized gains on mark-to-market and hedging transactions		81		1,379
Assets held for sale		2,736		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $16 at September 30, 2005 and $15 at December 31, 2004)		1,374		1,128
Other		1,967		1,896
Total investments and other assets		14,057		11,533
Property, Plant and Equipment
Cost		40,022		46,806
Less accumulated depreciation and amortization		11,422		13,300
Net property, plant and equipment		28,600		33,506
Regulatory Assets and Deferred Debits
Deferred debt expense		276		297
Regulatory assets related to income taxes		1,361		1,269
Other		930		894
Total regulatory assets and deferred debits		2,567		2,460
Total Assets	$	53,333	$	55,470

See Notes to Consolidated Financial Statements

2

PART I

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(Unaudited)

(In millions)

	September 30, 2005		December 31, 2004
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,307	$	2,414
Notes payable and commercial paper		67		68
Taxes accrued		824		273
Interest accrued		250		287
Liabilities associated with assets held for sale		1,605		30
Current maturities of long-term debt and preferred stock		983		1,832
Unrealized losses on mark-to-market and hedging transactions		249		819
Other		2,267		1,779
Total current liabilities		7,552		7,502
Long-term Debt		15,062		16,932
Deferred Credits and Other Liabilities
Deferred income taxes		4,960		5,228
Investment tax credit		146		154
Unrealized losses on mark-to-market and hedging transactions		57		971
Liabilities associated with assets held for sale		2,260		14
Asset retirement obligations		1,990		1,926
Other		4,608		4,682
Total deferred credits and other liabilities		14,021		12,975
Commitments and Contingencies
Minority Interests		650		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 September 30, 2005 and December 31, 2004, respectively		10,360		11,252
Retained earnings		5,014		4,539
Accumulated other comprehensive income		540		650
Total common stockholders’ equity		15,914		16,441
Total Liabilities and Common Stockholders’ Equity	$	53,333	$	55,470

See Notes to Consolidated Financial Statements

3

PART I

DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

(In millions)

	Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,218		$	1,132
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,463			1,524
Gains on sales of investments in commercial and multi-family real estate		(117	)		(149	)
(Gains) losses on sales of equity investments and other assets		(1,154	)		115
Deferred income taxes		(252	)		661
Minority interest		508			142
Equity in earnings of unconsolidated affiliates		(256	)		(110	)
Purchased capacity levelization		(12	)		93
Contribution to company-sponsored pension plans		(32	)		(14	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		922			198
Receivables		77			234
Inventory		(149	)		55
Other current assets		(993	)		(65	)
Increase (decrease) in
Accounts payable		(204	)		(667	)
Taxes accrued		611			242
Other current liabilities		758			96
Capital expenditures for residential real estate		(276	)		(218	)
Cost of residential real estate sold		159			127
Other, assets		(43	)		(199	)
Other, liabilities		293			306
Net cash provided by operating activities		2,521			3,503
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures		(1,649	)		(1,586	)
Acquisitions, net of cash acquired		(293	)		—
Purchases of available-for-sale securities		(30,489	)		(30,599	)
Proceeds from sales and maturities of available-for-sale securities		29,801			28,999
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		2,366			1,234
Proceeds from the sales of commercial and multi-family real estate		185			413
Settlement of net investment hedges and other investing derivatives		(244	)		—
Other		(20	)		(62	)
Net cash used in investing activities		(343	)		(1,601	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		286			166
Issuance of common stock and common stock related to employee benefit plans		36			948
Payments for the redemption of:
Long-term debt		(1,021	)		(1,735	)
Preferred stock of a subsidiary		—			(76	)
Notes payable and commercial paper		150			85
Distributions to minority interests		(576	)		(1,094	)
Contributions from minority interests		528			959
Dividends paid		(812	)		(798	)
Repurchase of common shares		(933	)		—
Other		5			2
Net cash used in financing activities		(2,337	)		(1,543	)
Changes in cash and cash equivalents included in assets held for sale		3			38
Net (decrease) increase in cash and cash equivalents		(156	)		397
Cash and cash equivalents at beginning of period		533			397
Cash and cash equivalents at end of period	$	377		$	794
Supplemental Disclosures
Significant non-cash transactions:
Debt retired in connection with disposition of businesses	$	—		$	840
Note receivable from sale of southeastern plants	$	—		$	48
Remarketing of senior notes	$	—		$	1,625

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, results of operations and cash flows. 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.

Effective July 1, 2005, Duke Energy has deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 10). DEFS has been subsequently accounted for as an equity method investment.

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

Reclassifications and Revisions. The accompanying Consolidated Statement of Cash Flows for the nine months ended September 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 $2,064 million and $763 million as of September 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 nine months ended September 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 nine months ended September 30, 2004 has increased by $52 million, while net cash used in investing activities for the nine months ended September 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. Such reclassifications include the reclassification of the results of certain operations from continuing operations to discontinued operations (see Note 13).

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 nine months ended September 30, 2005 and 2004.

	Income			Average Shares	EPS
	(in millions, except per-share data)
Three Months Ended September 30, 2005
Income from continuing operations	$	924
Less: Dividends and premiums on redemption of preferred and preference stock		(3	)
Income from continuing operations—basic	$	921		926	$	0.99
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				5
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	923		964	$	0.96
Three Months Ended September 30, 2004
Income from continuing operations	$	381
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)
Income from continuing operations—basic	$	379		938	$	0.40
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	381		973	$	0.39
Nine Months Ended September 30, 2005
Income from continuing operations	$	2,112
Less: Dividends and premiums on redemption of preferred and preference stock		(7	)
Income from continuing operations—basic	$	2,105		936	$	2.25
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock, and common stock derivatives				4
Contingently convertible bond		6		33
Income from continuing operations—diluted	$	2,111		973	$	2.17
Nine Months Ended September 30, 2004
Income from continuing operations	$	949
Less: Dividends and premiums on redemption of preferred and preference stock		(7	)
Income from continuing operations—basic	$	942		925	$	1.02
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		6		33
Income from continuing operations—diluted	$	948		960	$	0.99

The increase in weighted-average shares outstanding for the nine months ended September 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.

6

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 20, Duke Energy has revised diluted earnings per share for the three months ended September 30, 2004, from $0.41 to $0.40, and revised diluted earnings per share for the nine months ended September 30, 2004, from $1.21 to $1.18.

Options, restricted stock, performance and phantom stock awards related to approximately 17 million shares as of September 30, 2005, and 24 million shares as of September 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 nine months ended September 30, 2004, potential common shares related to Duke Energy’s $750 million of Equity Units, which resulted in the issuance of approximately 19 million shares in November 2004, are not included in “effect of dilutive securities” in the above table because their inclusion would be antidilutive.

See Note 3 for a discussion of conversion rights under Duke Energy’s $770 million contingently convertible bonds.

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 was to mature no later than November 8, 2005. Under the terms of the forward sale contract, the investment bank was required to 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. At settlement, Duke Energy, at its option, was required to 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 was higher than the March 18, 2005 closing price of $27.46 per share, or the investment bank was required to 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 was lower than the March 18, 2005 closing price of $27.46 per share. On September 22, 2005, Duke Energy, at its option, paid approximately $25 million in cash to the investment bank to settle the forward sale contract as the investment bank had repurchased the full 30 million shares in the open market and fulfilled all of its obligations. The amount paid to the investment bank was based upon the difference between the investment bank’s weighted average price paid for the 30 million shares purchased of $28.42 per share and the March 18, 2005 closing price of $27.46 per share.

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 was required, until settlement. Accordingly, Duke Energy recorded the approximately $25 million paid at settlement in Common Stockholders’ Equity as a reduction in 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. Duke Energy may terminate this plan at any time, without penalty. The timing of any repurchase of shares by the investment bank pursuant to this plan is dependent upon certain specified factors, including the market price of Duke Energy’s common stock. 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. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed (see Note 10). As of May 6, 2005, Duke Energy had already purchased approximately 2.6 million shares of its common stock pursuant to this plan at a weighted average price of $28.97 per share.

In October 2005, Duke Energy’s $770 million of convertible debt became convertible into approximately 33 million shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible debt may exercise their right to convert on or prior to December 31, 2005. During October 2005, approximately 1 million shares of common stock have been issued related to this conversion, which resulted in the retirement of approximately $25 million of convertible debt.

7

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	38		$	387		$	1,211		$	1,125
Add: stock-based compensation expense included in reported net income, net of related tax effects		8			5			24			10
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(8	)		(7	)		(24	)		(19	)
Pro forma earnings available for common stockholders, net of tax effects	$	38		$	385		$	1,211		$	1,116
EPS
Basic—as reported	$	0.04		$	0.41		$	1.29		$	1.22
Basic—pro forma	$	0.04		$	0.41		$	1.29		$	1.21
Diluted—as reported	$	0.04		$	0.40		$	1.25		$	1.18
Diluted—pro forma	$	0.04		$	0.40		$	1.25		$	1.17

5. Inventory

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

Inventory

	September 30,		December 31,
	2005		2004
	(in millions)
Materials and supplies	$	444	$	445
Natural gas		295		312
Coal held for electric generation		89		104
Petroleum products		51		81
Total inventory	$	879	$	942

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. 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 ability and intent to refinance those balances on a long-term basis.

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Notes To Consolidated Financial Statements—(Continued)

In August 2005, Duke Energy’s International Energy business unit issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On September 21, 2005, Union Gas Limited (Union Gas) entered into a fixed-rate financing denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents) due in 2016 with an interest rate of 4.64%.

See Note 3 for a discussion of conversion rights under Duke Energy’s $770 million contingently convertible bonds.

The current and non-current portions of DEFS’ long-term debt balances of approximately $600 million and approximately $1,650 million, respectively, as of December 31, 2004, are no longer included in Duke Energy’s consolidated long-term debt balance due to the deconsolidation of DEFS in July 2005.

Available Credit Facilities and Restrictive Debt Covenants. During the nine-month period ended September 30, 2005, Duke Energy’s consolidated credit capacity increased by approximately $325 million compared to December 31, 2004. Duke Energy renewed an expiring $150 million bi-lateral credit facility for an additional 364-day period. Duke Capital LLC (Duke Capital), a wholly owned subsidiary of Duke Energy, added a new $100 million, 364-day bi-lateral 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. Westcoast Energy Inc. (Westcoast) and 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 credit facilities of DEFS ($250 million at December 31, 2004) are no longer included in Duke Energy’s consolidated available credit facilities due to the deconsolidation of Duke Energy’s investment in DEFS in July 2005 (see Note 10). In October 2005, Duke Capital added a new $100 million, 364-day bi-lateral credit facility to provide additional letter of credit issuing capacity.

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 September 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 Facilities Summary as of September 30, 2005

	Expiration Date		Credit Facilities Capacity		Amounts Outstanding
					Commercial Paper		Letters of Credit		Total
	(in millions)
Duke Energy
$150 364-day bi-lateral (a), (b), (g)	September 2006	��
$500 multi-year syndicated (a), (b)	June 2010
Total Duke Energy			$	650	$	300	$	—	$	300
Duke Capital LLC
$800 364-day syndicated (a), (b)	June 2006
$600 multi-year syndicated (a), (b)	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		—		1,050		1,050
Westcoast Energy Inc.
$86 364-day syndicated (b), (c)	June 2006
$171 multi-year syndicated (b), (d)	June 2010
Total Westcoast Energy Inc.				257		67		—		67
Union Gas Limited
$257 364-day syndicated (e), (f)	June 2006			257		—		—		—
Total			$	3,174	$	367	$	1,050	$	1,417

(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.

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

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

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

(e) 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.

(f) 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.

(g) In September 2005, credit facility expiration date was extended from September 2005 to September 2006.

7. Employee Benefit Obligations

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

Components of Net Periodic Pension Costs (Income)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Duke Energy U.S.
Service cost	$	14		$	16		$	45		$	48
Interest cost on projected benefit obligation		39			40			118			120
Expected return on plan assets		(57	)		(59	)		(171	)		(175	)
Amortization of prior service cost credit		—			—			(1	)		(1	)
Amortization of net transition asset		—			(1	)		—			(3	)
Amortization of losses		9			4			26			11
Curtailment gain		—			—			—			(1	)
Net periodic pension costs (income)	$	5		$	—		$	17		$	(1	)
Westcoast
Service cost	$	2		$	2		$	6		$	6
Interest cost on projected benefit obligation		7			6			22			19
Expected return on plan assets		(7	)		(6	)		(20	)		(17	)
Amortization of prior service cost		1			—			1			—
Amortization of losses		1			1			3			2
Net periodic pension costs	$	4		$	3		$	12		$	10

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 nine month periods ended September 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 $9 million and $30 million to the Westcoast DB plans for the three and nine month periods ended September 30, 2005, respectively. Duke Energy anticipates that it will make total contributions of approximately $43 million in 2005. Duke Energy has contributed $0 million and $2 million to the Westcoast DC plans for the three and nine month periods ended September 30, 2005, respectively, and anticipates that it will make total contributions of approximately $3 million in 2005.

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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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Duke Energy U.S.
Service cost benefit	$	1		$	1		$	4		$	4
Interest cost on accumulated post- retirement benefit obligation		11			11			34			36
Expected return on plan assets		(4	)		(5	)		(13	)		(14	)
Amortization of net transition liability		4			4			12			12
Amortization of losses		2			2			6			7
Net periodic post-retirement benefit costs	$	14		$	13		$	43		$	45
Westcoast
Service cost benefit	$	1		$	1		$	2		$	2
Interest cost on accumulated post- retirement benefit obligation		2			1			4			3
Amortization of prior service cost credit		(1	)		—			(1	)		—
Amortization of losses		—			—			1			1
Net periodic post-retirement benefit costs	$	2		$	2		$	6		$	6

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 months ended September 30, 2005 compared to $12 million for the three months ended September 30, 2004. Duke Energy expensed employer matching contributions of $48 million for the nine months ended September 30, 2005 compared to $44 million for the nine months ended September 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 (Loss)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
	(in millions)
Net Income	$	41		$	389	$	1,218		$	1,132
Other comprehensive income
Foreign currency translation adjustments (a)		309			247		365			(37	)
Net unrealized gains on cash flow hedges (b)		165			89		401			268
Reclassification into earnings from cash flow hedges (c)		(878	)		14		(876	)		(40	)
Other comprehensive (loss) income, net of tax		(404	)		350		(110	)		191
Total Comprehensive (Loss) Income	$	(363	)	$	739	$	1,108		$	1,323

(a) Foreign currency translation adjustments, net of $62 million tax benefit for the nine months ended September 30, 2005, related to the settled net investment hedges (see Note 15). Substantially all of the tax benefit is an immaterial correction of an accounting error related to prior periods.

(b) Net unrealized gains on cash flow hedges, net of $107 million and $76 million tax expense for the three months ended September 30, 2005 and 2004, respectively, and $230 million and $142 million tax expense for the nine months ended September 30, 2005 and 2004, respectively.

(c) Reclassification into earnings from cash flow hedges, net of $502 million and $3 million tax benefit for the three months ended September 30, 2005 and 2004, respectively, and $501 million and $21 million tax benefit for the nine months ended September 30, 2005 and 2004, respectively. Reclassification into earnings from cash flow hedges for the three months and nine months ended September 30, 2005, is due primarily to the recognition of Duke Energy North America’s (DENA’s) unrealized net gains related to hedges on transactions which will

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Notes To Consolidated Financial Statements—(Continued)

no longer occur a result of the plan to sell or otherwise dispose of substantially all of DENA’s assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 13 and 15).

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 (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance as of December 31, 2004	$	540	$	526		$	(416	)	$	650
Other comprehensive income changes year- to-date (net of tax benefit of $333)		365		(475	)		—			(110	)
Balance as of September 30, 2005	$	905	$	51		$	(416	)	$	540

9. Goodwill

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142. As a result of the annual impairment tests required by SFAS No. 142, no charge for the impairment of goodwill was recorded in 2005.

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2004(a)		Impairments		Dispositions		Other(b)(c)			Balance September 30, 2005
	(in millions)
Natural Gas Transmission	$	3,416	$	—	$	—	$	85		$	3,501
Field Services		480		—		—		(480	)		—
International Energy		245		—		—		20			265
Crescent		7		—		—		—			7
Total consolidated	$	4,148	$	—	$	—	$	(375	)	$	3,773

(a) Amounts include an $18 million transfer of goodwill between Field Services and Natural Gas Transmission as a result of the transfer of Canadian assets in connection with the DEFS disposition transaction (see Note 10).

(b) As a result of the deconsolidation of DEFS in July 2005 goodwill decreased by $480 million (see Note 10).

(c) Other amounts consist primarily of foreign currency translation.

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

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Notes To Consolidated Financial Statements—(Continued)

tors. 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 16. 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, Natural Gas Transmission 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. This transaction, which closed in August 2005, increased Natural Gas Transmission’s ownership percentage of Saltville Storage to 100%.

In the second quarter of 2005, United Bridgeport Energy LLC (UBE), the owner of a 33 ¹/3% interest in Bridgeport Energy LLC (Bridgeport), exercised its “put right” requiring 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. The assets and liabilities of Bridgeport have been classified as Assets Held for Sale in the accompanying Consolidated Balance Sheet as of September 30, 2005, and will be included as part of the divestiture of DENA’s power generation assets in the eastern United States (see Note 13).

The pro-forma results of operations for the above completed acquisitions do not materially differ from reported results.

Dispositions.For the three months ended September 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $1 billion in proceeds, pre-tax gains of $580 million recorded in Gains (Losses) on Sales of Other Assets, net, on the accompanying Consolidated Statements of Operations. For the nine months ended September 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $2.2 billion in proceeds, net pre-tax gains of $589 million recorded in Gains (Losses) on Sales of Other Assets, net and pre-tax gains of approximately $1.2 billion recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the accompanying 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 13, 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 nine months ended September 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 were recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statement of Operations for the nine months ended September 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the nine months ended September 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 from ConocoPhillips and DEFS, consisting of approximately $.8 billion in cash and approximately $.3 billion of assets. The DEFS disposition resulted in pre-tax gain of approximately $575 million, which was recorded in Gains (Losses) on Sales of Other Assets, net in the accompanying Consolidated Statements of Operations. 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 purchase of the Empress System by Duke Energy was delayed pending damage repairs to the assets from a windstorm and as a result ConocoPhillips transferred approximately $230 million of cash to Duke Energy in July 2005. The Empress System was subsequently acquired by Duke Energy in August 2005 for cash of approximately $230 million. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. See Note 15 for

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Notes To Consolidated Financial Statements—(Continued)

the impacts of this transaction on certain cash flow hedges. The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see Note 14).

• Additional asset and business sales during the nine month period ended September 30, 2005 totaled $26 million in proceeds. These sales resulted in net pre-tax gains of approximately $14 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations.

For the three months ended September 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $108 million of proceeds and $63 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 nine months ended September 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $185 million of proceeds and $117 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 included a large land sale in Lancaster County, South Carolina during the three months ended September 30, 2005, that resulted in $42 million of pre-tax gains, and several other “legacy” land sales. Additionally, in the third quarter of 2005, Crescent had a $45 million gain on sale of an interest in a portfolio of commercial office buildings which was recognized in Other Income and Expenses, net, in the accompanying Consolidated Statements of Operations.

For the three months ended September 30, 2004, the sale of other assets resulted in approximately $530 million in proceeds, and net losses of $3 million recorded in Gains (Losses) on Sales of Other Assets, net and losses of $14 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the accompanying Consolidated Statement of Operations. For the nine months ended September 30, 2004, the sale of other assets resulted in approximately $674 million in proceeds, and net losses of $353 million recorded in Gains (Losses) on Sales of Other Assets, net and losses of $14 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales of other assets and equity investments during the nine months ended September 30, 2004 are as follows:

• As a result of the marketing efforts related to DENA’s eight natural gas-fired merchant power plants in the southeastern United States: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi); and certain other power and gas contracts (collectively, the Southeast Plants), Duke Energy classified those assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million 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 Gains (Losses) 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 United States. 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 Gains (Losses) on Sales of Other Assets, net in the accompanying 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 accompanying 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 September 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $110 million of proceeds and $28 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the accompanying Consolidated Statements of Operations. For the nine months ended September 30, 2004, Crescent’s commercial and multi-family real estate sales resulted in $413 million of proceeds, and $149 million of net pre-tax gains recorded in Gains on Sales of

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Notes To Consolidated Financial Statements—(Continued)

Investments in Commercial and Multi-Family Real Estate on the accompanying 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.

11. Severance

As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, in the third quarter of 2005, DENA recorded a severance accrual of approximately $22 million, under its ongoing severance plan, related to the anticipated involuntary termination of approximately 400 DENA employees by the end of the third quarter of 2006. Approximately $2 million of the related pre-tax expense is reflected in Operation, Maintenance and Other and approximately $20 million is reflected in Net operating (loss) income, net of tax, in Discontinued Operations in the accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2005. Additionally, DENA is also offering certain enhanced termination benefits to employees expected to be involuntarily terminated in connection with the DENA disposition plan; however, no severance accrual was recorded in the third quarter of 2005 related to the enhanced termination benefits, as the expected termination dates, and therefore, the expected future service periods, of affected DENA employees is not yet known due to the uncertainty around the timing and method of disposal of the related generation facilities and contracts. Once the expected service periods become estimable, which management anticipates may occur in the fourth quarter of 2005, Duke Energy will begin accruing the enhanced termination benefits over the estimated service periods. Management anticipates future severance costs incurred related to this exit plan will be approximately $30 million to $50 million.

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.

Severance Reserve

	Balance at December 31, 2004		Provision/ Adjustments			Noncash Reductions		Cash Reductions			Balance at September 30, 2005
	(in millions)
Franchised Electric	$	4	$	(2	)	$	—	$	(2	)	$	—
Natural Gas Transmission		6		—			—		(3	)		3
Field Services		—		1			—		(1	)		—
DENA		1		22			—		(1	)		22
International Energy		1		—			—		—			1
Crescent		—		—			—		—			—
Other		3		—			—		(2	)		1
Total (a)	$	15	$	21		$	—	$	(9	)	$	27

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

12. Impairments and Other Charges

International Energy. International Energy owns a 50% joint venture interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, a $20 million other than temporary impairment in value of the Campeche investment has been recognized during the third quarter of 2005 to write down the investment to its estimated fair value. This impairment is classified as a component of (Losses) Gains on Sales and Impairments of Equity Investments in the accompanying Consolidated Statements of Operations. An additional impairment charge could be recognized if the ultimate outcome of the above discussions is materially different than management’s current expectations.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Crescent.In the third quarter of 2005, Crescent recognized pre-tax impairment charges of approximately $16 million related to a residential community near Hilton Head Island, South Carolina, that includes both residential lots and a golf club, to reduce the carrying value of the community to its estimated fair value. This impairment was recognized as a component of Impairment and Other Charges in the accompanying Consolidated Statements of Operations. This community has incurred higher than expected costs and has been impacted by lower than anticipated sales volume. The fair value of the remaining community assets was determined based upon management’s estimate of discounted future cash flows generated from the development and sale of the community.

Field Services. See Note 15 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

In the third quarter of 2004, Duke Energy recorded impairments of approximately $22 million related to Field Services’ operating assets. The majority of this charge relates to an exchange transaction by Mobile Bay Processing Partners, which owns processing assets in the Onshore Gulf of Mexico, that resulted in the write-down of certain assets.

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

13. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations
			Net Operating (Loss) Income									Net (Loss) Gain on Dispositions
	Operating Revenues		Pre-tax Operating (Loss) Income			Income Tax (Benefit) Expense			Operating (Loss) Income, Net of Tax			Pre-tax (Loss) Gain on Dispositions			Income Tax (Benefit) Expense			(Loss) Gain on Dispositions, Net of Tax
	(in millions)
Three Months Ended September 30, 2005
DENA	$	663	$	(857	)	$	(316	)	$	(541	)	$	(535	)	$	(206	)	$	(329	)
International Energy		—		(10	)		(1	)		(9	)		—			—			—
Crescent		1		1			1			—			2			1			1
Other		—		—			—			—			(9	)		(4	)		(5	)
Total consolidated	$	664	$	(866	)	$	(316	)	$	(550	)	$	(542	)	$	(209	)	$	(333	)
Three Months Ended September 30, 2004
Field Services	$	10	$	—		$	—		$	—		$	(16	)	$	(6	)	$	(10	)
DENA		471		(2	)		(20	)		18			—			—			—
International Energy		—		(10	)		(1	)		(9	)		—			(5	)		5
Crescent		1		—			—			—			7			3			4
Total consolidated	$	482	$	(12	)	$	(21	)	$	9		$	(9	)	$	(8	)	$	(1	)
Nine Months Ended September 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—
DENA		1,540		(905	)		(329	)		(576	)		(512	)		(206	)		(306	)
International Energy		—		(6	)		2			(8	)		—			—			—
Crescent		2		1			1			—			2			1			1
Other		—		—			—			—			(9	)		(4	)		(5	)
Total consolidated	$	1,546	$	(910	)	$	(326	)	$	(584	)	$	(519	)	$	(209	)	$	(310	)
Nine Months Ended September 30, 2004
Field Services	$	54	$	2		$	1		$	1		$	(14	)	$	(5	)	$	(9	)
DENA		1,646		(151	)		(73	)		(78	)		(2	)		—			(2	)
International Energy		82		(7	)		—			(7	)		295			22			273
Crescent		2		—			—			—			7			3			4
Other		1		2			1			1			—			—			—
Total consolidated	$	1,785	$	(154	)	$	(71	)	$	(83	)	$	286		$	20		$	266

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 accompanying Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004.

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

	September 30, 2005		December 31, 2004
	(in millions)
Current assets	$	1,579	$	40
Investments and other assets		1,572		12
Net property, plant and equipment		1,164		72
Total assets held for sale	$	4,315	$	124
Current liabilities	$	1,605	$	30
Long-term debt and other deferred credits		2,260		14
Total liabilities associated with assets held for sale	$	3,865	$	44

Field Services

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

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

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

DENA

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets (see Notes 10 and 16 for further details on the anticipated Cinergy merger). The exit plan is expected to be completed by the end of the third quarter of 2006. In addition, management will continue to wind down the limited remaining operations of Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with Exxon Mobil Corporation. The financial statement presentation for the assets and contracts to be sold, and the related results of operations, are discussed below.

In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

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

17

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

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

In addition to these amounts, at September 30, 2005, approximately $150 million of pre-tax deferred net gains remain in AOCI related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings over the next 12 months as the forecasted transactions occur. In addition, management anticipates that additional charges will be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts estimated at approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 11); DENA may also realize future potential gains on sales of certain plants which will be recognized when sold. Subsequent to September 30, 2005, DENA has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. The total cash to be paid by Duke Energy under such contract sales or terminations is approximately $220 million. These transactions resulted in pre-tax losses on sale of approximately $90 million, which are included in the $600 million to $800 million range of additional anticipated charges, as discussed above.

The impairments have been classified as a component of Discontinued Operations-Net (Loss) Gain on Dispositions, net of tax, in the accompanying Consolidated Statements of Operations. See Note 15 for further details on the hedge accounting implications of this exit activity. The charge for the discontinuance of the normal purchase/normal sale exception and the reclassification of deferred gains in AOCI for cash flow hedges have been classified as a component of Discontinued Operations-Net Operating (Loss) Income, net of tax, in the Consolidated Statements of Operations.

The DENA assets to be divested include:

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

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

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

All of the assets and liabilities to be disposed of under the exit plan, have been classified as Assets Held for Sale in the accompanying Consolidated Balance Sheet as of September 30, 2005. In October 2005, the Ft. Frances generation facility was sold to a third party for proceeds which approximate the carrying value of the sold assets.

The results of operations of DENA’s western and eastern United States generation assets, including related commodity contracts, the Ft. Frances generation assets, substantially all of the contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, qualify for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations. In the first quarter of 2005, DENA’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excludes any potential contingent consideration).

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, as discussed further in Note 10, DENA’s Southeastern generation operations, including related commodity contracts do not qualify for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

See Note 14 for a discussion of the impacts of this exit activity on Duke Energy’s segment presentation.

18

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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). In the third quarter of 2005, DENA completed the sale of Bayside and the after-tax gain on this sale is included in Discontinued Operations-Net (Loss) Gain on Dispositions, net of tax, in the accompanying Consolidated Statements of Operations. Bayside was consolidated with the adoption of FASB Interpretation (FIN) No. 46 (Revised

18.1

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 accompanying Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.

International Energy

In order to eliminate exposure to international markets outside of Latin America and Canada, International Energy decided in 2003 to pursue a possible sale or initial public offering of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after-tax loss of $233 million during the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated 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 (Loss) 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 (Loss) Gain on Dispositions, net of tax, in the accompanying 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 (Loss) Gain on Dispositions, net of tax, in the accompanying 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 $43 million as of September 30, 2005 and $54 million as of December 31, 2004. This receivable is included in Receivables in the Consolidated Balance Sheets as of September 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 (Loss) Gain on Dispositions, net of tax, in the accompanying Consolidated Statements of Operations.

The operating results related to these operations were included in Discontinued Operations, net of tax, in the accompanying 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. If Crescent does not have 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 third quarter of 2005, Crescent sold one commercial property resulting in sales proceeds of approximately $14 million. The after-tax gain on that sale was included in Discontinued Operations-Net (Loss) Gain on Dispositions, net of tax, in the accompanying Consolidated Statements of Operations. As of September 30, 2005, Crescent had two commercial properties classified as Assets Held for Sale in the Consolidated Balance Sheets. The results of operations for those two properties are included in Discontinued Operations in the accompanying Consolidated Statement of Operations.

In the third quarter of 2004, Crescent sold one residential and one commercial property included in Assets Held for Sale on the Consolidated Balance Sheets resulting in sales proceeds of approximately $14 million. The after-tax gain on these sales was included in Discontinued Operations-Net (Loss) Gain on Dispositions, net of tax, in the accompanying Consolidated Statements of Operations.

19

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other

During 2003, Duke Energy decided to exit the merchant finance business conducted by Duke Capital Partners (DCP). The sale or collection of substantially 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.

14. 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. All of the business units are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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

As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended September 30, 2005 reduced Other’s segment losses by approximately $10 million. For the nine months ended September 30, 2005, the inclusion of DENA’s continuing operations increased Other’s segment losses by approximately $50 million. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

In connection with this exit plan, DENA recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005 as a component of Discontinued Operations in the accompanying Consolidated Statements of Operations. Approximately $1.9 billion of this charge relates to the disqualification of the normal purchase/normal sale exception for certain forward power and gas contracts, approximately $1.2 billion of pre-tax deferred net gains were reclassified out of AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan, and impairments of approximately $.6 billion to reduce the carrying value of the plants that are being sold to their estimated fair value less cost to sell.

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 10). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Energy’s Natural Gas Transmission segment. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

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

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 15 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).

20

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating, including equity in earnings of unconsolidated affiliates) 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.

Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Three Months Ended September 30, 2005
Franchised Electric	$	1,614	$	5		$	1,619		$	606
Natural Gas Transmission		857		12			869			329
Field Services (c)		—		—			—			701
International Energy		186		—			186			63
Crescent		105		—			105			120
Total reportable segments		2,762		17			2,779			1,819
Other (a)		266		16			282			(175	)
Eliminations		—		(33	)		(33	)		—
Interest expense		—		—			—			(228	)
Interest income and other (b)		—		—			—			(5	)
Total consolidated	$	3,028	$	—		$	3,028		$	1,411
Three Months Ended September 30, 2004
Franchised Electric	$	1,413	$	6		$	1,419		$	453
Natural Gas Transmission		615		37			652			269
Field Services (c)		2,531		(41	)		2,490			63
DENA (a)		53		22			75			(27	)
International Energy		146		—			146			64
Crescent		77		—			77			43
Total reportable segments		4,835		24			4,859			865
Other		246		49			295			(25	)
Eliminations		—		(73	)		(73	)		—
Interest expense		—		—			—			(329	)
Interest income and other (b)		—		—			—			17
Total consolidated	$	5,081	$	—		$	5,081		$	528

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

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

(c) In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

21

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Nine Months Ended September 30, 2005
Franchised Electric	$	4,103	$	15		$	4,118		$	1,216
Natural Gas Transmission		2,732		92			2,824			1,044
Field Services (c)		5,470		60			5,530			1,784
International Energy		536		—			536			217
Crescent		281		—			281			210
Total reportable segments		13,122		167			13,289			4,471
Other(a)		508		2			510			(495	)
Eliminations		—		(169	)		(169	)		—
Interest expense		—		—			—			(813	)
Interest income and other (b)		—		—			—			44
Total consolidated	$	13,630	$	—		$	13,630		$	3,207
Nine Months Ended September 30, 2004
Franchised Electric	$	3,901	$	17		$	3,918		$	1,215
Natural Gas Transmission		2,295		113			2,408			986
Field Services (c)		7,226		(72	)		7,154			243
DENA (a)		127		42			169			(514	)
International Energy		447		—			447			161
Crescent		216		—			216			190
Total reportable segments		14,212		100			14,312			2,281
Other		795		134			929			(56	)
Eliminations		—		(234	)		(234	)		—
Interest expense		—		—			—			(984	)
Interest income and other (b)		—		—			—			73
Total consolidated	$	15,007	$	—		$	15,007		$	1,314

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

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

(c) In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

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

22

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Segment Assets

	September 30, 2005			December 31, 2004
	(in millions)
Franchised Electric	$	18,440		$	18,199
Natural Gas Transmission		18,488			17,498
Field Services		1,579			6,436
DENA (a)		6,221			6,719
International Energy		3,260			3,329
Crescent		1,500			1,315
Total reportable segments		49,488			53,496
Other (a)		4,442			1,829
Reclassifications and eliminations (b)		(597	)		145
Total consolidated assets	$	53,333		$	55,470

(a) DENA’s segment assets include DENA assets held for sale and other assets not included in DENA’s continuing operations as of September 30, 2005, which are in Other (see Note 13).

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

15. Risk Management Instruments

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

Derivative Portfolio Carrying Value

	September 30, 2005			December 31, 2004
	(in millions)
Hedging	$	6		$	795
Trading		5			18
Undesignated		(107	)		(262	)
Total	$	(96	)	$	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, excluding approximately $2.9 billion of derivative assets and $3.7 billion of derivative liabilities which were transferred to assets and liabilities held for sale, as a result of the plan to exit DENA’s operations outside the midwestern United States (see Note 13).

As a result of the plan to exit DENA’s operations outside the Midwestern United States, approximately 6,200 megawatts of power generation located primarily in the western and northeastern United States region will be divested (see Note 13). As a result of the decision to pursue the sale or other disposition of substantially all of DENA’s remaining physical and commercial assets outside the midwestern United States, DENA discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception.

The $789 million decrease in the hedging derivative portfolio carrying value is due primarily to the transfer of hedging positions to held for sale, as discussed above.

The $155 million increase in the undesignated derivative portfolio fair value is due primarily to the transfer of DENA’s undesignated positions to held for sale, as discussed above and certain contract terminations at DENA, partially offset by the 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 10), Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted

23

PART I

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Notes To Consolidated Financial Statements—(Continued)

for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statement of Operations. As a result, approximately $105 million and $355 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy in the three months and nine months ended September 30, 2005, respectively. These charges have been classified in the accompanying Consolidated Statement of Operations for the nine months ended September 30, 2005 as follows: upon the discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairment and Other Charges while approximately $130 million and $105 million of losses recognized subsequent to discontinuance of hedge accounting were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues and Other Income and Expenses, respectively. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $80 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Included in Other Current Assets in the Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004 are collateral assets of approximately $1,535 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 changes in commodity prices. Included in Other Current Liabilities in the Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004 are collateral liabilities of approximately $1,035 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. These settlements are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows. 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 5 years.

As of September 30, 2005, approximately $190 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. This amount includes approximately $150 million related to the DENA exit plan discussed in Note 13. 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 gain of approximately $19 and a loss of approximately $11 million in the three and nine months ended September 30, 2005, respectively, as compared to a loss of approximately $8 and $3 million in the three and nine months ended September 30, 2004, respectively. The amount recognized for transactions that are probable of not occurring, was a pretax gain of approximately $1.2 billion in the three and nine months ended September 30, 2005, and is reported in Discontinued Operations in the Consolidated Statement of Operations. The disqualified cash flow hedges were primarily associated with DENA’s unrealized net gains on natural gas and power cash flow hedge positions (see Note 13).

Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Energy actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power.

The ineffective portion of commodity fair value hedges was immaterial for both the three and nine months ended September 30, 2005, and the three and nine months ended September 30, 2004.

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Normal Purchases and Normal Sales. The amount recognized for transactions that no longer qualified as normal purchases/normal sales was a pretax net loss of approximately $1.9 billion in the three and nine months ended September 30, 2005, and is reported in Discontinued Operations in the accompanying Consolidated Statement of Operations. The net loss recorded during the third quarter of 2005, which primarily included certain contracts that were being accounted for as normal purchases/normal sales, was recognized due to management’s plan for the sale or disposition of substantially all of DENA’s physical and commercial assets outside the midwestern United States and certain contractual positions related to the Midwestern assets (see Note 13).

16. Regulatory Matters

Merger with Cinergy. As discussed in Note 10, on May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Approval of the merger by several federal and state agencies is required. The status of these matters is as follows:

• During the second quarter of 2005, Cinergy filed a petition for approval of the merger with the Indiana Utility Regulatory Commission (IURC). Hearings are scheduled before the IURC in December 2005.

• During the second quarter of 2005, Duke Energy and Cinergy filed an application for approval of the merger with 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).

• In July 2005, Duke Energy filed an application for the approval of the merger with the North Carolina Utilities Commission (NCUC). Hearings are scheduled before the NCUC in December 2005.

• In July 2005, Duke Energy filed an application for the approval of the merger with the Public Service Commission of South Carolina (PSCSC). On November 1, 2005, the PSCSC approved the planned merger, which included approval of settlement agreements. Key terms of the settlements include a $40 million rate reduction for one year, a most favored nations clause related to merger savings sharing in other jurisdictions and a three-year extension to the Bulk Power Marketing profit sharing arrangement.

• In August 2005, Duke Energy and Cinergy filed an application for the approval of the merger with the Kentucky Public Service Commission (KPSC). In October 2005, Duke Energy and Cinergy filed a merger related settlement agreement with the KPSC, which included a $7.6 million rate credit over 5 years and a most favored nations clause related to merger savings sharing in other jurisdictions. A final order from the KPSC is expected by December 2005.

• In August 2005, Duke Energy filed its License Amendment Request with the Nuclear Regulatory Commission.

• On August 11, 2005, the Federal Trade Commission and U.S. Department of Justice granted early termination of the waiting period imposed by the Hart-Scott-Rodino Act.

During October and November 2005, Duke Energy and Cinergy filed 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 billion be amortized within the rate freeze period (2002 to 2007). Franchised Electric’s amortization expense related to this clean air legislation totals $567 million from inception, with approximately $85 million and $110 million recorded in the third quarter of 2005 and 2004, respectively, and $241 million and $142 million recorded for the first nine months of 2005 and 2004, respectively. As of September 30, 2005, cumulative expenditures totaled $337 million, with $213 million and $52 million incurred for the first nine months of 2005 and 2004, respectively, and are included in Net Cash 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

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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.

Decommissioning Studies.In June 2004, Duke Power Company (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. The PSCSC issued a requested accounting order in August 2005 for Duke Power to implement the new decommissioning funding levels.

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 a $100 million revenue reduction for previously recorded excess deferred tax 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 a $40 million revenue reduction which was approved by the PSCSC on September 15, 2005. These deferred tax revenue reductions are recorded as regulatory liabilities until paid to the customers.

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 had failed one of the applicable market screens. Under the FERC’s order, Duke Power may 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.

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

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provided if Union Gas earns below the allowed ROE, normalized for weather. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $7 million during the nine months ended September 30, 2005.

In response to direction from the OEB, Union Gas filed an application requesting approval of an increase in rates effective January 1, 2006 with continuation of the 2005 earnings sharing mechanism. In October 2005, the OEB found that the evidence provided was insufficient to grant Union Gas’s request and outlined further evidence needed to pursue this 2006 rate application. Union Gas has decided not to pursue this matter further. Accordingly, a rate order will be filed with the OEB effective January 1, 2006 to implement items previously approved by the OEB. It will also incorporate an earnings sharing mechanism for 2006 with characteristics similar to those ordered by the OEB for 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. M&N anticipates that FERC will act on the settlement agreement prior to the end of 2005.

On September 15, 2005, East Tennessee Natural Gas, LLC filed with FERC for approval of a rate settlement with its customers. On October 26, 2005, FERC issued an order accepting the settlement as filed and effective November 1, 2005. The settlement agreement includes a five year rate moratorium and certain operational changes.

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.

17. 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 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

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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.

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 $57 million as of September 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 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

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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 filed a request for rehearing with the Fourth Circuit, which was denied. The EPA may petition for further appellate review at the U.S. Supreme Court. 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.

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 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 settlements. 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 DETM relating to amounts owed in connection with the termination of bilateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in excess of $90 million. Based on the level of damages claimed by the plaintiff and Duke Energy’s assessment of possible outcomes in this matter, Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

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

Trading Related Litigation. By letter dated April 16, 2004, Duke Energy received notice that a shareholder reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same “round trip” trades issues raised in the shareholder lawsuits dismissed by the courts in 2003 and affirmed on appeal, the notice stated that the shareholder intended to initiate derivative shareholder litigation

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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, and on September 30, 2005, the court issued an order granting class certification. 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. Defendants removed this case to the United States District Court for the Western District of Tennessee in March 2005. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

On August 8, 2005, a plaintiff filed a lawsuit in state court in Kansas against Duke Energy and DETM, as well as other energy companies, claiming that the plaintiff 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 entering into unlawful arrangements and agreements. Duke Energy removed this case to the United States District Court for the District of Kansas on September 8, 2005. On September 26, 2005, a class action petition was filed by two plaintiffs in state court in Kansas against various defendants including Duke Energy and DETM, based on substantially similar allegations. The plaintiffs in the foregoing cases claim the defendants violated Kansas’ antitrust laws and seek damages in unspecified amounts. 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 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

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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.

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 counter 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 $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The hearing on damages issues commenced in September 2005 and will continue through the first quarter of 2006.

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. The parties filed cross motions for partial summary judgment regarding the letter of credit issue which were subsequently denied by the Court. No trial date has been set. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with the Sonatrach and Citrus matters.

ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. ExxonMobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that ExxonMobil breached its Ventures obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of ExxonMobil’s claims. ExxonMobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. ExxonMobil also filed a motion to dismiss certain of Duke Energy’s counterclaims. The parties have submitted briefs on the reconsideration motion and the motion to dismiss, both of which remain pending. A hearing on the motions is scheduled for December 2005. In response to a request from ExxonMobil, the arbitration panel 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

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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 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 September 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 September 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.

Other Commitments and Contingencies

Hurricane Damage. Duke Energy continues to assess and monitor damage incurred in the third quarter of 2005 related to Hurricanes Katrina and Rita in the Gulf Coast, but is currently not aware of any damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position.

18. 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 and its subsidiaries enter 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 September 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 September 30, 2005, DCS’

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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.

DPSG and the other owners of DCS have issued a guarantee to the DOE, which in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Energy estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of September 30, 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 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 September 30, 2005, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and an initial segment of 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 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” because DPSG and Duke Power are under common control.

Other Guarantees and Indemnifications.Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of September 30, 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 September 30, 2005 was approximately $15 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 September 30, 2005 was approximately $700 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 $125 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 September 30, 2005, Duke Capital had guaranteed approximately $10 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, International Energy, and Crescent 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, International Energy, or Crescent would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of September 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. Crescent was the guarantor of approximately $15 million of debt associated with less than wholly owned entities, which expire in 2006.

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

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agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Energy is unable to estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of September 30, 2005, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

19. Related Party Transactions

In October 2005, Gulfstream Natural Gas System, LLC (Gulfstream) issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. Gulfstream is a 50% unconsolidated entity owned by Natural Gas Transmission with the remaining 50% being owned by Williams Companies, Inc. The partnership owns 691 miles of interstate natural gas pipeline and transports gas from the Mobile Bay, Alabama area to Florida markets. The proceeds were used by Gulfstream to pay off a construction loan and the balance, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentage.

In July 2005, DEFS was deconsolidated due to the transfer of a 19.7% interest to ConocoPhillips and has been subsequently accounted for as an equity investment (see Note 10). Duke Energy’s 50% of equity in earnings of DEFS for the three-months ended September 30, 2005 was $126 million and Duke Energy’s investment in DEFS as of September 30, 2005 was $1,504 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. During the three-months ended September 30, 2005, Duke Energy had gas sales to and purchases from affiliates of DEFS of approximately $28 million and $30 million, respectively. As of September 30, 2005, Duke Energy had trade receivables from and trade payables to DEFS amounting to approximately $3 million and $50 million, respectively. Additionally, Duke Energy has recognized an approximate $70 million receivable as of September 30, 2005 due to its share of a distribution declared by DEFS in September 2005 but paid in October 2005. Summary financial information for DEFS, which is accounted for under the equity method, as of and for the three-months ended September 30, 2005 is as follows:

	Three-months Ended September 30, 2005
	(in millions)
Operating revenues	$	3,386
Operating expenses	$	3,105
Operating income	$	281
Net income	$	252
	September 30, 2005
	(in millions)
Current assets	$	2,615
Non-current assets	$	4,628
Current liabilities	$	2,475
Non-current liabilities	$	1,827

DEFS is a limited liability company which is a pass-through entity for U.S. income tax purposes. DEFS also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DEFS. Therefore, DEFS’ net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognizes the tax impacts of its share of DEFS’ pass-through earnings in its income tax expense from continuing operations in the accompanying Consolidated Statements of Operations.

Also see Notes 10, 12, 14 and 18 for additional related party information.

20. New Accounting Standards

The following new accounting standards were adopted by Duke Energy subsequent to September 30, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 2.” 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

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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 on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

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, cash flows or financial position.

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 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

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No. 03-13 was effective for Duke Energy beginning January 1, 2005. The adoption of EITF Issue No. 03-13 did not have a material impact on Duke Energy’s 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 September 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 supersedes 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 adjusted 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 and for all new awards or modifications to previous awards after the adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period adjusted.

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 nine month periods ended September 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 plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model 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.

FASB Interpretation No. 47 (FIN 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 continues to evaluate FIN 47, but currently does not anticipate the adoption of FIN 47 will have any material impact on its consolidated results of operations, cash flows or financial position. Duke Energy does not currently intend to restate any interim financial information to reflect the adoption of FIN 47.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence.” In July of 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18 requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a con - -

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Notes To Consolidated Financial Statements—(Continued)

solidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 is effective for Duke Energy beginning October 1, 2005. Duke Energy does not anticipate the adoption of FSP No. APB 18-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

21. 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 nine months of 2005, Duke Energy recognized a benefit of approximately $5 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 liability of $45 million as of December 31, 2004. During the 2nd quarter of 2005, Duke Energy reorganized various entities which enabled it to reduce the $45 million tax liability to $41 million. Duke Energy repatriated approximately $360 million of extraordinary dividends during the nine months ended September 30, 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 such matters. As of September 30, 2005, Duke Energy has total provisions of approximately $130 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.

The effective tax rate for the three months ended September 30, 2005 was approximately 35%, compared to approximately 28% for the same period in 2004. The increase in the effective tax rate was due primarily to a $20 million tax benefit in 2004 recognized in connection with the prior year formation of Duke Energy Americas, LLC (DEA). The effective tax rate for the nine months ended September 30, 2005 was approximately 34%, compared to approximately 28% 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 and a $20 million tax benefit in 2004 recognized in connection with the prior year formation of DEA.

22. Subsequent Events

In November 2005, Duke Energy Income Fund (the “Fund”) filed a preliminary prospectus with securities regulatory authorities in Canada for an initial public offering of trust units of the Fund. The Fund was established to acquire all of the common shares of Duke Energy Midstream Services Canada Corporation (“Duke Midstream”) from a subsidiary of Duke Energy. Duke Energy will retain an interest

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

in the Fund. The offering is expected to be completed by the end of 2005. The units have not been, and will not be, registered under United States securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

For information on subsequent events related to common stock, debt and credit facilities, discontinued operations and assets held for sale, regulatory matters, and related party transactions, see Notes 3, 6, 13, 16, and 19.

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DUKE ENERGY CORPORATION

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.

As discussed in Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”, on May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they entered into a definitive merger agreement. 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 Note 16 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 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.

As discussed in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of Duke Energy North America’s (DENA) remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets. The exit plan is expected to be completed by the end of the third quarter of 2006.

RESULTS OF OPERATIONS

Results of Operations and Variances

	Three Months Ended September 30,									Nine Months Ended September 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	3,028		$	5,081		$	(2,053	)	$	13,630		$	15,007		$	(1,377	)
Operating expenses		2,138			4,236			(2,098	)		11,308			12,567			(1,259	)
Gains on sales of investments in commercial and multi-family real estate		63			28			35			117			149			(32	)
Gains (losses) on sales of other assets, net		580			(3	)		583			589			(353	)		942
Operating income		1,533			870			663			3,028			2,236			792
Other income and expenses, net		116			49			67			1,500			208			1,292
Interest expense		228			329			(101	)		813			984			(171	)
Minority interest expense		10			62			(52	)		508			146			362
Earnings from continuing operations before income taxes		1,411			528			883			3,207			1,314			1,893
Income tax expense from continuing operations		487			147			340			1,095			365			730
Income from continuing operations		924			381			543			2,112			949			1,163
(Loss) income from discontinued operations, net of tax		(883	)		8			(891	)		(894	)		183			(1,077	)
Net income		41			389			(348	)		1,218			1,132			86
Dividends and premiums on redemption of preferred and preference stock		3			2			1			7			7			—
Earnings available for common stockholders	$	38		$	387		$	(349	)	$	1,211		$	1,125		$	86

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Overview of Drivers and Variances

Three Months Ended September 30, 2005 as Compared to September 30, 2004.For the three months ended September 30, 2005, earnings available for common stockholders were $38 million, or $0.04 per basic share and $0.04 per diluted share. For the three months ended September 30, 2004, earnings available for common stockholders were $387 million, or $0.41 per basic share and $0.40 per diluted share. Significant items that contributed to decreased earnings available for common stockholders for the quarter included:

• An approximate $0.9 billion loss from discontinued operations in 2005 driven primarily by an approximate $0.8 billion non-cash, after-tax charge (approximately $1.3 billion pre-tax) for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, as discussed in the “Introduction” above. As a result of the DENA exit plan, all of the operations of DENA, except for the Midwestern operations, remaining Southeastern operations, and Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with Exxon Mobil Corporation), have been classified as discontinued operations (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”)

• A $340 million increase in income tax expense from continuing operations, resulting primarily from higher pre-tax earnings, primarily the gains associated with the transfer of 19.7% of Duke Energy’s interest in Duke Energy Field Services, LLC (DEFS) to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), and a $20 million tax benefit in the third quarter 2004 recognized in connection with the prior year formation of Duke Energy Americas, LLC (DEA) (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions” and Note 21 to the Consolidated Financial Statements, “Income Tax Expense”), and

• An approximate $105 million of unrealized and realized pre-tax losses recognized in the third quarter 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 deconsolidation of DEFS by Duke Energy (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”).

Partially offsetting these amounts were:

• An approximate $575 million pre-tax gain recorded in 2005 as a result of the DEFS disposition transaction

• An approximate $150 million pre-tax increase in earnings at Franchised Electric due primarily to the impacts of warmer weather, increased sales to wholesale customers, and the impact of continued growth in the number of retail customers, partially offset by increased operating and maintenance costs

• A $101 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004 and the deconsolidation of DEFS in 2005

• An approximate $80 million pre-tax increase in earnings (net of minority interest benefit of $1 million) at Crescent Resources LLC (Crescent) due primarily to the gain on sale of an interest in a portfolio of office buildings and a large land sale in the third quarter 2005, partially offset by decreased commercial project sales due to four commercial projects being sold in 2004, and

• A $60 million pre-tax increase in earnings (net of minority interest of $1 million) at Natural Gas Transmission due primarily to higher earnings from business operations and expansion projects and favorable foreign exchange rate from the strengthening Canadian currency.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004. For the nine months ended September 30, 2005, earnings available for common stockholders were approximately $1.2 billion, or $1.29 per basic share and $1.25 per diluted share. For the nine months ended September 30, 2004, earnings available for common stockholders were approximately $1.1 billion, or $1.22 per basic share and $1.18 per diluted share. Significant items that contributed to increased earnings available for common stockholders for the nine months included:

• An approximate $800 million pre-tax gain (net of minority interest of $343 million) recorded in 2005 on the sale of DEFS’ wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, L.P. (TEPPCO LP), an equity method investment of DEFS

• An approximate $575 million pre-tax gain recorded in 2005 as a result of the DEFS disposition transaction

• An approximate $360 million pre-tax charge in 2004 associated with the sale of DENA’s 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)

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• An approximate $200 million pre-tax increase in earnings (net of minority interest of approximately $50 million) at Field Services, excluding the impact of those hedges which were discontinued as cash flow hedges and the TEPPCO GP, TEPPCO LP and DEFS disposition transaction gains, due primarily to the favorable effects of commodity prices, net of hedging. This amount includes approximately $50 million negative impact due to the decrease in ownership in DEFS as a result of the DEFS disposition transaction.

• A $171 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004 and the deconsolidation of DEFS in 2005

• 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 $100 million pre-tax increase in earnings (net of minority interest benefit of $5 million) from DENA continuing operations due primarily to lower operating and general and administrative expenses, and an approximate $40 million favorable impact related to hedge discontinuance in the Midwest and Southeast

• An approximate $60 million pre-tax increase in earnings (net of minority interest of $3 million) at Natural Gas Transmission due primarily to higher earnings from business operations and expansion projects in the U.S. and favorable foreign exchange rate from the strengthening Canadian currency, and

• An approximate $60 million pre-tax increase in earnings at International Energy due primarily to improved performance in Peru and Argentina, favorable foreign exchange rate changes in Brazil and higher product margins at National Methanol Company (NMC).

Partially offsetting these amounts were:

• A $1.1 billion after-tax decrease from discontinued operations driven primarily by an approximate $0.8 billion non-cash, after-tax impairment charge (approximately $1.3 billion pre-tax) recorded in 2005 related to the decision to exit substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, as discussed above, and a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business) (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”)

• A $730 million increase in income tax expense from continuing operations, resulting primarily from higher pre-tax earnings, primarily the gains associated with the sale of TEPPCO GP, the DEFS disposition transaction and the sale of Duke Energy’s limited partner interest in TEPPCO LP, all discussed above, the release of various income tax reserves in the second quarter 2004 totaling approximately $52 million, and a $20 million tax benefit in the third quarter 2004 recognized in connection with the prior year formation of DEA (see Note 21 to the Consolidated Financial Statements, “Income Tax Expense”)

• An approximate $355 million of unrealized and realized 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 15 to the Consolidated Financial Statements, “Risk Management Instruments”), and

• An approximate $55 million pre-tax charge to increase liabilities associated with mutual insurance companies.

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

Consolidated Operating Revenues

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated operating revenues for the three months ended September 30, 2005 decreased approximately $2.1 billion, compared to the same period in 2004. This change was driven primarily by:

• A $2.5 billion decrease due to the deconsolidation of DEFS effective July 1, 2005, and

• A $128 million decrease in revenue as a result of the continued wind-down of Duke Energy Merchants LLC (DEM).

Partially offsetting these decreases in revenues were:

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• A $217 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily the Empress System gas processing and natural gas liquids marketing business (Empress System), increased gas distribution revenues, resulting from higher gas usage in the power market, favorable foreign exchange rates as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses) and an increase related to U.S. business operations driven by higher rates and contracted volumes

• A $200 million increase at Franchised Electric due primarily to increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet, and customer growth coupled with an increase in fuel rates primarily as a result of higher coal costs in 2005, and

• A $40 million increase at International Energy due primarily to favorable foreign exchange rate changes in Brazil, and higher energy prices and volumes.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated operating revenues for the nine months ended September 30, 2005 decreased approximately $1.4 billion, compared to the same period in 2004. This change was driven primarily by:

• A $2.5 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005

• A $456 million decrease in revenue as a result of the continued wind-down of DEM, and

• 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 15 to the Consolidated Financial Statements, “Risk Management Instruments”) from February 22, 2005 to June 30, 2005. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to these discontinued hedges are classified in Other income and expenses on the Consolidated Statements of Operations.

Partially offsetting these decreases in revenues were:

• An approximate $850 million increase at Field Services, excluding the impact of those hedges which were discontinued as cash flow hedges and the impact of the deconsolidation of DEFS, due primarily to higher average commodity prices, primarily Natural Gas Liquid (NGL) and natural gas in the first six months of 2005

• A $416 million increase at Natural Gas Transmission due primarily to favorable foreign exchange rates as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), higher natural gas prices that are passed through to customers, new Canadian assets, primarily the Empress System, an increase related to U.S. business operations driven by higher rates and contracted volumes and increased gas distribution revenues, resulting from higher gas usage in the power market

• A $200 million increase at Franchised Electric due primarily to increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet, and customer growth, coupled with an increase in fuel rates primarily as a result of higher coal costs in 2005

• An $89 million increase at International Energy due primarily to favorable foreign exchange rate changes in Brazil, and higher energy prices and volumes, and

• A $65 million increase at Crescent due primarily to higher residential developed lot sales.

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

Consolidated Operating Expenses

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated operating expenses for the three months ended September 30, 2005 decreased approximately $2.1 billion, compared to the same period in 2004. This change was driven primarily by:

• A $2.4 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

• A $132 million decrease due to the continued wind-down of DEM.

Partially offsetting these decreases in expenses were:

• A $151 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily gas purchase costs associated with the Empress System, increased gas purchases for distribution primarily due to higher gas usage in the power market, and an increase caused by foreign exchange impacts, discussed above (offset by currency impacts to revenues)

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• A $59 million increase in operating expenses at Franchised Electric due primarily to increased fuel expenses, driven by higher coal costs and increased generation to meet customer demand, and increased operating and maintenance expenses due primarily to increased planned power plant maintenance and outage costs, partially offset by decreased regulatory amortization in 2005

• A $33 million increase at Crescent due primarily to an impairment charge in 2005 related to a residential community near Hilton Head, South Carolina as a result of higher than expected costs and lower than anticipated sales volume and increased costs of residential developed lot sales due to increased sales, and

• A $30 million increase at International Energy due primarily to higher fuel prices and the impact of foreign exchange rate changes in Brazil.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated operating expenses for the nine months ended September 30, 2005 decreased approximately $1.3 billion, compared to the same period in 2004. This change was driven primarily by:

• A $2.4 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005

• A $442 million decrease due to the continued wind-down of DEM, and

• An approximate $100 million decrease in operating expenses at DENA, mainly resulting from the sale of the Southeast Plants

Partially offsetting these decreases in expenses were:

• An approximate $675 million increase in operating expenses at Field Services driven primarily by higher average NGL and natural gas prices in the first six months of 2005

• A $356 million increase at Natural Gas Transmission due primarily to increased natural gas prices at Union Gas Limited (Union Gas) (offset in revenues), foreign exchange impacts, discussed above (offset by currency impacts to revenues), increased gas purchases for distribution primarily due to higher gas usage in the power market and new Canadian assets, primarily gas purchase costs associated with the Empress System

• A $202 million increase in operating expenses at Franchised Electric due primarily to increased fuel expenses, driven by higher coal costs and increased generation to meet customer demand, and increased operating and maintenance expenses due primarily to increased planned outage costs and maintenance at generating plants

• 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 15 to the Consolidated Financial Statements, “Risk Management Instruments”)

• An approximate $55 million charge to increase liabilities associated with mutual insurance companies

• A $52 million increase at Crescent due primarily to increased cost associated with the development of residential lots as a result of increased lot sales and the impairment charge in 2005 related to a residential community near Hilton Head, South Carolina, discussed above, and

• A $47 million increase at International Energy due primarily to higher fuel prices, increased fuel volumes purchased, higher in maintenance costs and the impact of foreign exchange rate changes in Brazil, offset by decreased power purchase obligations in Brazil.

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

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

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated gains on sales of investments in commercial and multi-family real estate for the three months ended September 30, 2005 increased $35 million, compared to the same period in 2004 primarily as a result of a gain from a large land sale in 2005, partially offset by decreased commercial project sales due to four commercial projects being sold in 2004.

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Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated gains on sales of investments in commercial and multi-family real estate for the nine months ended September 30, 2005 decreased $32 million, compared to the same period in 2004. The decrease was due primarily to the gain on sale of the Alexandria tract in June 2004 and a commercial project in the Washington, D.C. area in March 2004, partially offset by a large land sale in the third quarter 2005.

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

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated gains (losses) on sales of other assets, net for the three months ended September 30, 2005 increased $583 million, compared to the same period in 2004. The increase was due primarily to the gain resulting from the DEFS disposition transaction.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated gains (losses) on sales of other assets, net for the nine months ended September 30, 2005 increased $942 million, compared to the same period in 2004. The increase was due primarily to the gain resulting from the DEFS disposition transaction in 2005 and the charge in 2004 associated with the sale of DENA’s Southeast Plants.

Consolidated Operating Income

Three Months Ended September 30, 2005 as Compared to September 30, 2004. Consolidated operating income for the three months ended September 30, 2005 increased $663 million, compared to the same period in 2004. Increased operating income was due primarily to a gain resulting from the DEFS disposition transaction, favorable results at Franchised Electric driven by increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet and customer growth, and a gain from a large land sale in 2005 at Crescent.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated operating income for the nine months ended September 30, 2005 increased $792 million, compared to the same period in 2004. Increased operating income was due primarily to the gain resulting from the DEFS disposition transaction, the charge in 2004 associated with the sale of DENA’s Southeast Plants, lower operating expenses at DENA, mainly resulting from the sale of the Southeast Plants, favorable results at Natural Gas Transmission driven by higher earnings from business operations and expansion projects in the U.S. and favorable foreign exchange rate from thestrengthening Canadian currency, and favorable results at International Energy driven primarily by higher volumes and prices and favorable foreign 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 and increased liabilities associated with mutual insurance companies.

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 September 30, 2005 as Compared to September 30, 2004. Consolidated other income and expenses, net for the three months ended September 30, 2005 increased $67 million, compared to the same period in 2004. This increase was driven primarily by equity income for the investment in DEFS subsequent to the deconsolidation of DEFS, effective July 1, 2005, a gain on the sale of an interest in a portfolio of office buildings, and increased earnings from International Energy’s NMC investment driven by higher product margins, partially offset by unrealized and realized pre-tax losses recognized in the third quarter 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 deconsolidation of DEFS by Duke Energy (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”) and an impairment charge related to Compania de Servicios de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico, an International Energy equity investment.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated other income and expenses, net for the nine months ended September 30, 2005 increased approximately $1.3 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, equity income for the investment in DEFS subsequent to the deconsolidation of DEFS, effective July 1, 2005, a gain on the sale of an interest in a portfolio of office buildings, and increased earnings from International Energy’s NMC investment driven by higher product margins, slightly offset by the unrealized and realized pre-tax losses recognized in the third quarter 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 deconsolidation of DEFS by Duke Energy and an impairment charge related to Campeche. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to the Field Services discontinued hedges are classified in Other income and expenses on the Con - -

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solidated Statements of Operations, while from February 22, 2005 to June 30, 2005 these mark-to-market changes were classified in Non-regulated electric, natural gas, natural gas liquids and other revenues on the Consolidated Statements of Operations.

Consolidated Interest Expense

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated interest expense for the three months ended September 30, 2005 decreased $101 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004 (an approximate $50 million impact) and the deconsolidation of DEFS (an approximate $40 million impact).

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated interest expense for the nine months ended September 30, 2005 decreased $171 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004 (an approximate $140 million impact) and the deconsolidation of DEFS (an approximate $40 million impact).

Consolidated Minority Interest Expense

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated minority interest expense for the three months ended September 30, 2005 decreased $52 million, compared to the same period in 2004 driven primarily by a decrease related to the deconsolidation of DEFS and a decrease due to the continued wind-down of DETM.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated minority interest expense for the nine months ended September 30, 2005 increased $362 million, compared to the same period in 2004 driven primarily by increased earnings at DEFS in the first six months of 2005 as a result of the sale of TEPPCO GP and higher commodity prices, offset by the impact of the deconsolidation of DEFS effective July 1, 2005.

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended September 30, 2005 as Compared to September 30, 2004. Consolidated income tax expense from continuing operations for the three months ended September 30, 2005 increased $340 million, compared to the same period in 2004. The effective tax rate for the three months ended September 30, 2005 was approximately 35%, compared to approximately 28% for the same period in 2004. The increase in the effective tax rate was due primarily to a $20 million tax benefit in 2004 recognized in connection with the prior year formation of DEA. Additionally, the increase in income tax expense from continuing operations is a result of $883 million in higher pre-tax earnings due primarily to the DEFS disposition transaction (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Nine Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated income tax expense from continuing operations for the nine months ended September 30, 2005 increased $730 million, compared to the same period in 2004. The effective tax rate for the nine months ended September 30, 2005 was approximately 34%, compared to approximately 28% for 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 and a $20 million tax benefit in 2004 recognized in connection with the prior year formation of DEA. Additionally, the increase in income tax expense from continuing operations is a result of approximately $1.9 billion in higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP, Duke Energy’s limited partner interest in TEPPCO LP and the DEFS disposition transaction (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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

Three Months Ended September 30, 2005 as Compared to September 30, 2004.Consolidated (loss) income from discontinued operations, net of tax for the three months ended September 30, 2005 decreased $891 million, compared to the same period in 2004. This decrease was driven primarily by an approximate $0.8 billion non-cash, after-tax charge (approximately $1.3 billion pre-tax) for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all DENA operations except for the Midwestern operations, remaining Southeastern operations, and DETM, as announced in September 2005. As a result of the DENA exit plan, all of the operations of DENA, excluding the operations mentioned above, have been classified as discontinued operations (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

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Nine Months Ended September 30, 2005 as Compared to September 30, 2004. Consolidated (loss) income from discontinued operations, net of tax for the nine months ended September 30, 2005 decreased approximately $1.1 billion, compared to the same period in 2004. This decrease was driven primarily by an approximate $0.8 billion non-cash, after-tax impairment charge (approximately $1.3 billion pre-tax) related to DENA, discussed above, and a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Segment Results

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.

As discussed in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

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

EBIT by Business Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Franchised Electric	$	606		$	453		$	1,216		$	1,215
Natural Gas Transmission		329			269			1,044			986
Field Services (a)		701			63			1,784			243
DENA (b)		—			(27	)		—			(514	)
International Energy		63			64			217			161
Crescent		120			43			210			190
Total reportable segment EBIT		1,819			865			4,471			2,281
Other (b)		(175	)		(25	)		(495	)		(56	)
Interest expense		(228	)		(329	)		(813	)		(984	)
Interest income and other (c)		(5	)		17			44			73
Consolidated earnings from continuing operations before income taxes	$	1,411		$	528		$	3,207		$	1,314

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(a) In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

(b) Other includes DENA’s continuing operations for 2005. DENA segment data includes continuing operations for DENA for periods prior to 2005.

(c) Other includes foreign currency transaction 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 September 30,						Nine Months Ended September 30,
	2005		2004		Increase (Decrease)		2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	1,619	$	1,419	$	200	$	4,118	$	3,918	$	200
Operating expenses		1,026		967		59		2,916		2,714		202
Gains on sales of other assets, net		1		—		1		2		3		(1	)
Operating income		594		452		142		1,204		1,207		(3	)
Other income, net of expenses		12		1		11		12		8		4
EBIT	$	606	$	453	$	153	$	1,216	$	1,215	$	1
Sales, Gigawatt-hours (GWh)		23,724		21,904		1,820		65,318		63,954		1,364

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

Increase over prior year	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005
Residential sales (a)	12.4	%	1.2	%
General service sales (a)	5.3	%	1.0	%
Industrial sales (a)	0.7	%	1.6	%
Wholesale sales	92.5	%	19.8	%
Total Franchised Electric sales	8.3	%	2.1	%
Average number of customers	1.9	%	2.0	%

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

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

Operating Revenues. The increase was driven primarily by:

• A $98 million increase in GWh sales to retail customers due to favorable weather conditions during the quarter. Weather statistics were 19% better than normal in third quarter 2005 compared to 14% less than normal during the same period in 2004

• A $70 million increase in fuel revenues, driven by increased megawatt-hour (MWh) sales to retail and wholesale customers and increased fuel rates for retail customers due primarily to increased coal costs. Sales to residential and commercial customers increased by approximately 10% and sales to wholesale customers increased by approximately 90%, resulting in significantly more fuel revenue billed to those customers. The delivered cost of coal in 2005 is approximately $3 per ton higher than the same period in 2004

• A $56 million increase in wholesale power revenues, due primarily to higher prices and increased sales volumes. Average prices were up approximately 75% over the same period in 2004, primarily due to higher natural gas prices. Wholesale MWh sales increased by approximately 80% due to strong demand driven by favorable weather, alleviation of coal constraints in 2004 that limited wholesale sales opportunities and more efficient performance by the generation fleet in 2005, partially offset by

• A $12 million decrease related to the sharing of profits from wholesale power sales with industrial customers in North Carolina in 2005. During third quarter 2005, sharing of profits was $16 million, while during third quarter 2004, sharing of profits was $4 million. The increased sharing is driven by increased wholesale sales.

Operating Expenses.The increase was driven primarily by:

• A $72 million increase in fuel expenses, due primarily to higher coal costs and increased generation to meet the strong demand of retail and wholesale customers. Generation fueled by coal accounted for approximately 55 percent of total generation during the third quarter of 2005 as compared to 50 percent during the same period in 2004. The delivered cost of coal in 2005 is approximately $3 per ton higher than the same period in 2004

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• A $12 million increase in operating and maintenance expenses, due primarily to increased power plant maintenance and outage costs in Nuclear Operations of $23 million; partially offset by decreased storm costs of $9 million, driven by charges related to hurricanes Ivan and Frances in 2004, partially offset by

• A $25 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during the third quarter of 2005 as compared to the same period in 2004. 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 $85 million for the three months ended September 30, 2005 as compared to approximately $110 million during the same period in 2004.

Other (expense) income, net.The increase was driven primarily by:

• A $6 million increase related to a true-up of a reserve related to wholesale customers.

• A $5 million increase in the allowance for funds used during construction (AFUDC), due primarily to ongoing relicensing projects.

EBIT. EBIT for the three months ended September 30, 2005 increased compared to the same period in 2004, due primarily to increased sales to retail customers due to favorable weather, increased sales to wholesale customers and reduction of regulatory amortization. These changes were partially offset by sharing of profits from wholesale power sales and increased operating and maintenance expenses.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $90 million increase in fuel revenues, due primarily to increased MWh sales to wholesale customers and increased fuel rates for retail customers due primarily to increased coal costs. Sales to wholesale customers increased by 20%, resulting in significantly more fuel revenue collections from those customers. The delivered cost of coal in 2005 is approximately $6 per ton higher than the same period in 2004

• An $83 million increase in wholesale power revenues, due primarily to increased sales volumes and higher market prices. Wholesale MWh sales increased by approximately 20% due to strong demand driven by favorable weather, more efficient performance by the generation fleet in 2005 and alleviation of coal constraints in 2004 that limited wholesale sales opportunities. Market prices were up approximately 40% over the same period in 2004

• A $26 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. The number of customers in 2005 has increased by approximately 43,000 compared to the same period in 2004

• A $20 million increase in GWh sales to retail customers due to favorable weather conditions, with hot summer weather offsetting milder weather in the winter and spring, partially offset by

• A $20 million decrease related to the sharing of profits from wholesale power sales with industrial customers in North Carolina in 2005. For the nine months ended September 30, 2005, the sharing of profits was $38 million, while for the same period in 2004, sharing of profits was $18 million.

Operating Expenses.The increase was driven primarily by:

• A $111 million increase in fuel expenses, due primarily to higher coal costs and increased generation to meet the strong demand of retail and wholesale customers. Total generation increased by 3% compared to 2004 and generation fueled by coal accounted for more than 50 percent of total generation during both periods. The delivered cost of coal in 2005 is approximately $6 per ton higher than the same period in 2004, and

• A $91 million increase in operating and maintenance expenses, due primarily to increased planned outage and maintenance at generating plants and increased planned maintenance to improve the reliability of distribution and transmission equipment.

EBIT. EBIT for the nine months ended September 30, 2005 was essentially flat compared to the same period in 2004, due primarily to increased sales to wholesale customers, net of sharing, partially offset by increased operating and maintenance expenses.

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Matters Impacting Future Franchised Electric Results

Management has previously disclosed that Franchised Electric’s annual EBIT growth rate over the 2005 to 2007 period was expected to be in the zero to two percent range. Franchised Electric expects segment EBIT for 2005 to be slightly above 2004 segment EBIT of $1,467 million. For the periods beyond 2005, due in part to charges or synergies that could result from the proposed merger with Cinergy Corp. (Cinergy), Franchised Electric is not able to estimate reported segment EBIT.

Natural Gas Transmission

	Three Months Ended September 30,							Nine Months Ended September 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	869	$	652	$	217		$	2,824	$	2,408	$	416
Operating expenses		549		398		151			1,809		1,453		356
Gains on sales of other assets, net		—		3		(3	)		4		12		(8	)
Operating income		320		257		63			1,019		967		52
Other income, net of expenses		17		19		(2	)		48		39		9
Minority interest expense		8		7		1			23		20		3
EBIT	$	329	$	269	$	60		$	1,044	$	986	$	58
Proportional throughput, TBtu (a)		759		652		107			2,534		2,467		67

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

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

Operating Revenues.The increase was driven primarily by:

• A $94 million increase due to new Canadian assets, primarily the Empress System

• A $34 million increase in gas distribution revenues, primarily due to higher gas usage in the power market

• A $34 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 $27 million increase for U.S. business operations driven by higher rates and contracted volumes

• A $5 million increase in Union Gas distribution revenues, primarily due to a rate design shift in the pattern of cost recoveries

• A $5 million increase from completed and operational pipeline expansion projects in the U.S., and

• A $4 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a markup at Union Gas. This revenue increase is offset in expenses.

Operating Expenses.The increase was driven primarily by:

• A $90 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System

• A $37 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market

• A $26 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above), and

• A $4 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

Other Income, net of expenses.The decrease was driven primarily by a $5 million gain in 2004 on the sale of Gas Transmission’s interest in the Millennium Pipeline project.

EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, Union Gas rate design timing impacts, favorable U.S. operations, contributions from new Canadian assets and favorable foreign exchange rate impacts from the strengthening Canadian currency.

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Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues.The increase was driven primarily by:

• A $127 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 $109 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a markup at Union Gas. This revenue increase is offset in expenses

• A $95 million increase due to new Canadian assets, primarily the Empress System

• A $40 million increase for U.S. business operations driven by higher rates and contracted volumes

• A $28 million increase in gas distribution revenues, primarily due to higher gas usage in the power market

• A $15 million increase from completed and operational pipeline expansion projects in the U.S., partially offset by

• A $7 million decrease at Union Gas primarily resulting from a new earnings-sharing mechanism effective January 1, 2005 (see Note 16 to the Consolidated Financial Statements, “Regulatory Matters.”)

Operating Expenses.The increase was driven primarily by:

• A $109 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $97 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

• A $96 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System

• A $35 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market, 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 the successful completion of the Gulfstream Natural Gas System LLC (Gulfstream) Phase II project which went into service in February 2005 and increased volumes at Gulfstream, resulting in a $10 million increase in Gas Transmission’s 50% equity earnings and a $5 million construction fee received from an affiliate. These increases were partially offset by a $5 million gain in 2004 on the sale of Gas Transmission’s interest in the Millennium Pipeline project.

EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, improved U.S. operations and favorable foreign exchange rate impacts from the strengthening Canadian currency, partially offset by the 2004 resolution of ad valorem tax issues.

Field Services

	Three Months Ended September 30,									Nine Months Ended September 30,
	2005			2004			Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues		—		$	2,490		$	(2,490	)	$	5,530	$	7,154	$	(1,624	)
Operating expenses		—			2,368			(2,368	)		5,211		6,785		(1,574	)
Gains on sales of other assets, net		576			1			575			577		1		576
Operating income		576			123			453			896		370		526
Equity in earnings of unconsolidated affiliates (a)		126			—			126			126		—		126
Other income (loss), net of expenses		(1	)		(17	)		16			1,259		17		1,242
Minority interest expense		—			43			(43	)		497		144		353
EBIT	$	701		$	63		$	638		$	1,784	$	243	$	1,541
Natural gas gathered and processed/transported, TBtu/d (b)		6.7			6.8			(0.1	)		6.8		6.8		—
NGL production, MBbl/d (c)		342			357			(15	)		355		354		1
Average natural gas price per MMBtu (d), (e), (f)	$	8.37		$	5.76		$	2.61		$	7.12	$	5.81	$	1.31
Average NGL price per gallon (e), (f)	$	0.91		$	0.72		$	0.19		$	0.80	$	0.64	$	0.16

(a) Includes Duke Energy’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Duke Energy’s equity in earnings was $126 million for the three and nine months ended September 30, 2005. Results of DEFS prior to July 1, 2005 are presented on a consolidated basis.

(b) Trillion British thermal units per day

(c) Thousand barrels per day

(d) Million British thermal units

(e) Index-based market price

(f) Does not reflect results of commodity hedges.

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In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction) and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for as an investment utilizing the equity method of accounting (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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

Operating Revenues and Expenses.The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Duke Energy’s 50% of equity in earnings related to its investment in DEFS is included in Equity in Earnings of Unconsolidated Affiliates.

Gain on sales of other assets, net.The increase was primarily due to an approximate pre-tax gain of $575 million on the DEFS disposition transaction.

Equity in earnings of unconsolidated affiliates. The increase was driven by the equity in earnings of $126 million for Duke Energy’s investment in DEFS subsequent to the completion of the DEFS disposition transaction and related deconsolidation. DEFS earnings during the third quarter 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due to hurricane interruptions.

Other Income, net of expenses. The increase was driven primarily by a $23 million impairment charge in 2004 related to management’s assessment of the recoverability of some equity method investments.

Minority Interest Expense.The decrease was due to the DEFS disposition transaction and the related deconsolidation of Duke Energy’s investment in DEFS on July 1, 2005.

EBIT. The increase was primarily due to the approximately $575 million gain on transfer related to the DEFS disposition transaction and an increase in DEFS results attributable to a $0.19 per gallon increase in average NGL prices and a $2.61 per MMBtu increase in average natural gas prices. These increases in EBIT were partially offset by the impact of Duke Energy’s decreased ownership in DEFS as a result of the DEFS disposition transaction.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues.The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Subsequent to July 2005, Duke Energy’s 50% of equity in earnings related to its investment in DEFS are included in Equity in Earnings of Unconsolidated Affiliates. This decrease was partially offset by increased revenues of approximately $850 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to a $0.14 per gallon increase in average NGL prices and a $0.66 per MMBtu increase in average natural gas prices.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Subsequent to July 2005, the results of DEFS are included in Other income, net of expenses. This decrease was partially offset by:

• Increased operating expense of approximately $675 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices, and

• 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 previously accounted for as cash flow hedges (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”). After the discontinuance of these hedges, changes in their fair value are being recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from the Field Services’ results.

Gain on sales of other assets, net.The increase was primarily due to an approximate pre-tax gain of $575 million on the DEFS disposition transaction.

Equity in earnings of unconsolidated affiliates. The increase was driven by the equity in earnings of $126 million for Duke Energy’s investment in DEFS subsequent to the completion of the DEFS disposition transaction and related deconsolidation. DEFS earnings during the third quarter 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due to hurricane interruptions.

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

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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 minority interest impact of 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. This increase was partially offset by the DEFS disposition transaction and the related deconsolidation of Duke Energy’s investment in DEFS effective July 1, 2005.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, the gain as a result of the DEFS disposition transaction and favorable effects of commodity price increases, partially offset by the impact of Duke Energy’s decreased ownership percentage resulting from the completion of the DEFS disposition transaction. 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 15 to the Consolidated Financial Statements, “Risk Management Instruments”). As a result of the discontinuance of these cash flow hedges and 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 nine months ended September 30, 2005. Field Services’ future results are subject to volatility for factors such as commodity price changes.

Supplemental Data

Below is supplemental information for DEFS operating results subsequent to deconsolidation on July 1, 2005:

	Three Months Ended September 30, 2005
	(in millions)
Operating revenues	$	3,386
Operating expenses		3,105
Operating income		281
Other income, net of expenses		2
Interest expense, net		33
Income tax benefit		2
Net income	$	252

Duke Energy North America

	Three Months Ended September 30,								Nine Months Ended September 30,
	2005		2004			Increase (Decrease)			2005		2004			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—	$	75		$	(75	)	$	—	$	169		$	(169	)
Operating expenses		—		88			(88	)		—		318			(318	)
(Losses) Gains on sales of other assets, net		—		(4	)		4			—		(373	)		373
Operating loss		—		(17	)		17			—		(522	)		522
Other income, net of expenses		—		5			(5	)		—		6			(6	)
Minority interest expense (benefit)		—		15			(15	)		—		(2	)		2
EBIT	$	—	$	(27	)	$	27		$	—	$	(514	)	$	514
Actual plant production, GWh		—		887			(887	)		—		3,300			(3,300	)
Proportional megawatt capacity in operation										—		3,600			(3,600	)

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

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ern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, and the remaining operations of DETM) have been reclassified to Other beginning in 2005. DENA’s continuing operations for 2004 are included as a component of DENA’s segment earnings. The results of DENA’s discontinued operations for 2004 and 2005 are presented in Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in “Consolidated (Loss) Income from Discontinued Operations, net of tax” above.

Three Months Ended September 30, 2005 as compared to September 30, 2004

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

• $49 million of power generation revenues, and

• $26 million of other operating revenues, primarily driven by mark-to-market gains recognized on DETM power contracts.

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

• $36 million of fuel costs

• $32 million of operations, maintenance and depreciation expenses, and

• $20 million of general and administrative expenses.

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

Nine Months Ended September 30, 2005 as compared to September 30, 2004

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

• $175 million of power generation revenues, and

• $(6) million of other operating revenues, primarily associated with DETM.

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

• $145 million of fuel costs

• $126 million of operations, maintenance and depreciation expenses

• $60 million of general and administrative expenses, and

• A $13 million ($8 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Losses on Sales of Other Assets, net. The change is due to the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results include pre-tax losses of approximately $360 million 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.

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

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International Energy

	Three Months Ended September 30,							Nine Months Ended September 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	186	$	146	$	40		$	536	$	447	$	89
Operating expenses		139		109		30			385		338		47
Gain on Sale of Assets		1		1		—			1		1		—
Operating income		48		38		10			152		110		42
Other income, net of expenses		19		29		(10	)		74		60		14
Minority interest expense		4		3		1			9		9		—
EBIT	$	63	$	64	($	1	)	$	217	$	161	$	56
Sales, GWh		4,493		4,277		216			13,555		13,088		467
Proportional megawatt capacity in operation									4,064		4,136		(72	)

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

Operating Revenues.The increase was driven primarily by:

• A $17 million increase due to exchange rate changes primarily in Brazil

• An $11 million increase in Argentina driven by higher volumes and prices

• A $7 million increase in Ecuador due to higher energy sales volumes due to lack of water for hydro competitors, and

• A $5 million increase in El Salvador primarily due to higher energy prices.

Operating Expenses. The increase was driven primarily by:

• A $14 million increase in Ecuador due primarily to higher diesel fuel prices and volumes as well as prior year credit related to long term service contract termination

• A $10 million increase due to exchange rate changes primarily in Brazil

• A $6 million increase in El Salvador due to higher fuel prices

• A $5 million increase in Guatemala mainly due to higher legal costs related to a contract dispute for the Planta Arizona plant, in addition to higher O&M costs, partially offset by

• A $7 million decrease in Peru’s power purchases due to increased generation as a result of favorable water availability.

Other Income, net of expenses. The decrease was driven primarily by a $20 million equity investment impairment related to Campeche as a result of discussions to either sell the investment or renew the gas compression services agreement, partially offset by $12 million increase in equity earnings from the NMC investment driven by higher product margins.

EBIT. The decrease was due primarily to the Campeche impairment discussed above, offset by favorable hydrological conditions in Peru and Argentina, higher equity earnings from NMC and favorable exchange rate impacts.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $36 million increase due to exchange rate changes primarily in Brazil

• A $30 million increase in Guatemala and El Salvador due to higher energy prices

• An $18 million increase in Argentina due primarily to higher volumes and higher prices

• A $13 million increase in Ecuador due to higher volumes

• A $4 million increase in revenues due to favorable hydrological conditions in Peru, partially offset by

• An $11 million decrease in Brazil mainly due to decreased prices, partially offset by higher sales volumes.

Operating Expenses.The increase was driven primarily by:

• A $26 million increase in Ecuador due to unplanned maintenance, higher fuel prices, increased fuel volumes purchased and increased transmission costs

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• A $21 million increase in El Salvador due primarily to higher fuel prices, increased fuel volumes purchased and increased transmission costs

• An $18 million increase due to exchange rate changes primarily in Brazil

• A $11 million increase in Guatemala due to higher legal costs related to a contract dispute for the Planta Arizona plant, in addition to higher O&M costs

• A $10 million increase in Argentina’s power purchases due to higher contracted energy and greater prices, partially offset by

• An $18 million decrease in Brazil due to reduced power purchase obligations

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

• An $8 million decrease in Peru’s power purchases due to increased generation as a result of favorable water availability.

Other Income, net of expenses. The increase was driven primarily by a $32 million increase in equity earnings from the NMC investment driven by higher product margins, offset by a $20 million equity investment impairment related to Campeche.

EBIT. The increase was due primarily to favorable hydrological conditions in Peru and Argentina, favorable exchange rates in Brazil and higher equity earnings from NMC and a charge associated with the disposition of the ownership share in Cantarell recorded in 2004, partially offset by an equity investment impairment and lower results in Central America and Ecuador.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.

International Energy’s long-term sales contracts and long-term debt in Brazil contain annual and monthly inflation adjustment clauses, respectively. While this is favorable to revenue in periods of inflation, as contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of local currency debt. In periods of deflation, revenue is negatively impacted and interest expense is positively impacted.

Campeche operates a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, an other than temporary impairment in value of the Campeche has occurred and a $20 million impairment charge was recorded during the three months ended September 30, 2005 to write down the investment to its estimated fair value as of September 30, 2005 (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”). An additional impairment charge would be recognized if the outcome of the above discussions are materially different than management’s current expectations.

Crescent

	Three Months Ended September 30,								Nine Months Ended September 30,
	2005			2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions)
Operating revenues	$	105		$	77	$	28		$	281	$	216	$	65
Operating expenses		95			62		33			225		173		52
Gains on sales of investments in commercial and multi-family real estate		63			28		35			117		149		(32	)
Operating income		73			43		30			173		192		(19	)
Other income, net of expenses		46			—		46			44		—		44
Minority interest (benefit) expense		(1	)		—		(1	)		7		2		5
EBIT	$	120		$	43	$	77		$	210	$	190	$	20

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

Operating Revenues.The increase was due primarily to a $28 million increase in residential developed lot sales primarily due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina.

Operating Expenses.The increase was due to a $16 million impairment charge in 2005 related to a residential community near Hilton Head, South Carolina due to higher than expected costs and lower than anticipated sales volume, a $10 million increase in the cost of residential developed lot sales due to increased sales as noted above and a $6 million increase in corporate administrative expenses due to increased operating results.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate.The increase was due primarily to a $42 million gain from a large land sale in Lancaster County, South Carolina in 2005, partially offset by an $11 million decrease in commercial project sales due to four commercial projects being sold in the prior year quarter.

Other Income, Net. The increase was due primarily to a $45 million gain on sale of an interest in a portfolio of commercial office buildings in the third quarter of 2005.

EBIT. The increase was due primarily to the gain on sale of the commercial investment noted above and the large land sale in Lancaster County, South Carolina.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues.The increase was driven primarily by a $70 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina, the LandMar affiliate in Florida, and The Sanctuary project on Lake Wylie near Charlotte, North Carolina.

Operating Expenses.The increase was driven primarily by a $34 million increase in the cost of residential developed lot sales, due to increased sales noted above along with a $16 million impairment charge in 2005 related to a residential community near Hilton Head, South Carolina due to higher than expected costs and lower than anticipated sales volume.

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

• A $45 million gain from the sale of the Alexandria tract in the Washington, D.C. area in June of 2004

• A $20 million gain from the sale of a commercial project in the Washington, D.C. area in March of 2004, partially offset by

• A $42 million gain from a large land sale in Lancaster County, South Carolina in 2005

Other Income, Net. The increase was due to a $45 million gain on sale of an interest in a portfolio of commercial office buildings in the third quarter of 2005.

EBIT. The increase was due primarily to the gain on sale of the commercial investment noted above, a large land sale in Lancaster County, South Carolina and increased residential developed lot sales, partially offset by the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in 2004.

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 significantly higher than segment EBIT from continuing operations and discontinued operations of approximately $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.

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Other

	Three Months Ended September 30,									Nine Months Ended September 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	282		$	295		$	(13	)	$	510		$	929		$	(419	)
Operating expenses		360			316			44			920			1,014			(94	)
Gains (losses) on sales of other assets, net		3			(3	)		6			6			4			2
Operating loss		(75	)		(24	)		(51	)		(404	)		(81	)		(323	)
Other (loss) income, net of expenses		(103	)		(1	)		(102	)		(98	)		25			(123	)
Minority interest benefit		(3	)		—			3			(7	)		—			7
EBIT	$	(175	)	$	(25	)	$	(150	)	$	(495	)	$	(56	)	$	(439	)

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended September 30, 2005 reduced Other’s segment losses by approximately $10 million. For the nine months ended September 30, 2005, the inclusion of DENA’s continuing operations increased Other’s segment losses by approximately $50 million.

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

Operating Revenues. The decrease was driven primarily by:

• A $128 million decrease in revenue as a result of the continued wind-down of DEM, partially offset by

• A $109 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s revenues from continuing operations consists primarily of $80 million of power generation revenues and $38 million related to mark-to-market gains as a result of hedge discontinuance in the Midwest and Southeast, partially offset by losses associated with structured power contracts in the Southeast.

Operating Expenses. The increase was driven primarily by:

• A $102 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s expenses from continuing operations consists primarily of $60 million of fuel costs, $23 million of operations and maintenance expenses, and $19 of general and administrative expenses

• A $54 million increase primarily due to the recognition of reserves for estimated property damage and increased reinsurance premiums related to hurricanes in 2005, business interruption losses, and timing of other captive insurance claims

• A $14 million increase in corporate governance costs in 2005, partially offset by

• A $132 million decrease as a result of the continued wind-down of DEM.

Other Income, net of expenses. The decrease was driven primarily by an approximate $105 million decrease as a result of the realized and unrealized mark-to-market impact on crashed hedges related to the DEFS disposition transaction.

EBIT.The decrease was due primarily to the realized and unrealized mark-to-market impact on discontinued cash flow hedges related to the DEFS disposition transaction, the recognition of losses for estimated property damage losses related to hurricanes in the third quarter of 2005, business interruption losses, and increased corporate governance in 2005.

Nine Months Ended September 30, 2005 as Compared to September 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $456 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 realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”), partially offset by

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• A $151 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s revenues from continuing operations consists primarily of $129 million of power generation revenues and $38 million related to mark-to-market gains as a result of hedge discontinuance in the Midwest and Southeast, partially offset by losses associated with structured power contracts in the Southeast.

Operating Expenses. The decrease was driven primarily by:

• A $442 million decrease as a result of the continued wind-down of DEM, partially offset by

• A $214 million increase in expenses as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s expenses from continuing operations consists of $100 million of fuel costs, $66 million of operations and maintenance expenses, and $48 of general and administrative expenses

• An approximate $55 million charge to increase liabilities associated with mutual insurance companies

• A $47 million increase primarily due to the recognition of reserves for estimated property damage and increased reinsurance premiums related to hurricanes in the third quarter of 2005, business interruption losses, and timing of other captive insurance claims, 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.

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

• An approximate $105 million decrease as a result of the realized and unrealized mark-to-market impact on crashed hedges related to the DEFS disposition transaction, and

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

EBIT.The decrease was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the realized and unrealized mark-to-market impact on discontinued cash flow hedges related to the DEFS disposition transaction, the movement of DENA’s continuing operations to Other in the third quarter of 2005, the recognition of losses for estimated property damage losses related to hurricanes in the third quarter of 2005, business interruption losses, the increase in liabilities associated with mutual insurance companies and the 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.

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 September 30, 2005 was a liability of approximately $245 million, and approximately $100 million of this value is attributable to contracts which will settle in 2005. As these contracts settle Duke Energy will realize an offset to revenue at Field Services. Additionally, future impacts due to losses insured by Bison as well as changes in liabilities associated with mutual insurance companies could impact future earnings for Other.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased approximately $1 billion for the nine months ended September 30, 2005, compared to the same period in 2004 due to approximately $600 million of additional net cash collateral posted by Duke Energy during 2005 attributable to increased crude oil prices, as well as increases to the forward market prices of power, a $480 million increase in taxes paid in 2005 as well as the impacts of the deconsolidation of DEFS effective July 1, 2005. These decreases were offset slightly by positive operating cash from the remaining operations.

Investing Cash Flows

Net cash used in investing activities decreased approximately $1.3 billion for the nine months ended September 30, 2005 as compared to the same period in 2004. This decrease in cash used was principally driven by proceeds from the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP for approximately $1.2 billion and DEFS disposition transaction proceeds of approximately $925 million, offset by the approximate $1.2 billion in proceeds received in 2004 primarily from the sales of the Southeast Plants and Asia-Pacific business. Additionally, during 2004, approximately $1 billion was invested in short-term investments as a result of the 2004 disposition trans - -

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actions and increased operating cash flows, as discussed above, which resulted in excess cash balances being invested in these short-term investments. These decreases in cash used were partially offset by an approximate $360 million increase in 2005 capital and investment expenditures primarily due to the $230 million acquisition of the Empress System.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased approximately $800 million for the nine months ended September 30, 2005, compared to the same period in 2004. This change was due primarily to the repurchase of 32.6 million shares of common stock for $933 million in 2005, 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 $975 million of higher redemptions, net of paydowns, of long-term debt, commercial paper, notes payable, and preferred stock of a subsidiary during 2004 in connection with an effort to reduce debt balances.

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 remaining 2005 capital expenditures and dividend payments.

With cash, cash equivalents and short-term investments on hand of approximately $1.4 billion as of September 30, 2005, along with a more stable business environment, Duke Energy has financial flexibility to buy back common stock (see Note 3 to the Consolidated Financial Statements, “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 partially completed Gray’s Harbor power generation facility (Grays Harbor) 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 August 2005, Duke Energy’s International Energy business unit issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On September 21 2005, Union Gas entered into a fixed-rate financing denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents) due in 2016 with an interest rate of 4.64%.

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”). The final settlement with the investment bank occurred on September 22, 2005 for approximately $25 million in cash. The final settlement price was the difference between the initial settlement price of $27.46 per share and the volume weighted average price per share of actual shares purchased by the investment bank of $28.42 per share. Duke Energy also entered into a separate open-market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of May 6, 2005, Duke Energy had already 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, in connection with the proposed merger with Cinergy, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). For the nine months ended September 30, 2005 a total of 32.6 million shares of common stock were repurchased under both share repurchase programs.

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In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. Gulfstream is a 50% unconsolidated entity owned by Natural Gas Transmission with the remaining 50% being owned by Williams Companies, Inc. The partnership owns 691 miles of interstate natural gas pipeline and transports gas from the Mobile Bay, Alabama area to Florida markets. The proceeds were used by Gulfstream to pay off a construction loan and the balance, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentage.

Available Credit Facilities and Restrictive Debt Covenants.Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of September 30, 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 November 1, 2005 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM. The credit ratings for DEFS is no longer included in the table, consistent with the deconsolidation of Duke Energy’s investment in DEFS in July 2005.

Credit Ratings Summary as of November 1, 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
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 credit 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 on “Stable”.

In September, 2005 Standard & Poor’s Ratings Service affirmed the credit ratings of Duke Energy and its subsidiaries (excluding Maritimes & Northeast Pipeline LLC and Maritimes and Northeast Pipeline LP) with a Stable outlook removing them from “CreditWatch with negative implications.” In addition, Dominion Bond Rating Service confirmed the credit rating of Westcoast Energy Inc. with a Stable trend removing them from “Under Review with Developing Implications.”

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 as well as the completion of the exit from the DENA business could impact the credit ratings of Duke Energy or its

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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. During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s assets and contracts outside the Midwestern United States.

A reduction in DETM’s credit rating to below investment grade as of September 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $200 million. Additionally, as a result of DETM’s credit rating as of September 30, 2005, Duke Capital could be required to segregate up to approximately $430 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 September 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 September 30, 2005, Duke Capital could have been required to pay up to $5 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.

Duke Energy expects a majority of the negative impact of the collateral position to reverse within the next twelve months, upon completion of the DENA exit plan.

Other Financing Matters.As of September 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 September 30, 2005, Duke Energy had access to 700 million Canadian dollars (approximately U.S. $598 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 expire in November 2005 and 200 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”). The forward sale contract was settled during the third quarter of 2005. 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 nine months of 2005, there were no material changes in Duke Energy’s contractual obligations and commercial commitments other than an approximate $3,450 million reduction in long-term debt (including interest), an approximate $340 million reduction in energy commodity contracts, and an approximate $150 million reduction in operating lease obligations due to the deconsolidation of DEFS in July 2005. 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.

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OTHER ISSUES

Merger with Cinergy.On May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at September 30, 2005, the holding company would issue approximately 310 million shares to convert the Cinergy common shares. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, 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 16 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 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/A has been filed with the SEC by Duke Energy Holding Corp. (Registration No. 333-126318), containing a preliminary joint proxy statement/prospectus.

Energy Policy Act of 2005. The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA) of 1936, directs FERC to establish 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 reactors, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission projects, streamlines the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. FERC’s 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 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions.” In the third quarter of 2005, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. Duke Energy is currently evaluating these proposals and does not anticipate that these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

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

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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.

Hurricane Damage. Duke Energy continues to assess and monitor damage incurred in the third quarter of 2005 related to Hurricanes Katrina and Rita in the Gulf Coast, but is currently not aware of any damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position.

(For additional information on other issues related to Duke Energy, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 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 September 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 supersedes Accounting Principles Board (APB) Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Timing for implementation of SFAS No. 123R, as amended in April 2005 by the SEC, is no later than the beginning of the first annual period beginning after June 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. Under SFAS No. 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be adjusted 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 and for all new awards or modifications to previous awards after the adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period adjusted.

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 nine month periods ended September 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 plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model 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

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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.

FASB Interpretation No. 47 (FIN 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 continues to evaluate FIN 47, but currently does not anticipate the adoption of FIN 47 will have any material impact on its consolidated results of operations, cash flows or financial position. Duke Energy does not currently intend to restate any interim financial information to reflect the adoption of FIN 47.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence.” In July of 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18 requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a consolidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 is effective for Duke Energy beginning October 1, 2005. Duke Energy does not anticipate the adoption of FSP No. APB 18-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

Subsequent Events

In November 2005, Duke Energy Income Fund (the “Fund”) filed a preliminary prospectus with securities regulatory authorities in Canada for an initial public offering of trust units of the Fund. The Fund was established to acquire all of the common shares of Duke Energy Midstream Services Canada Corporation (“Duke Midstream”) from a subsidiary of Duke Energy. Duke Energy will retain an interest in the Fund. The offering is expected to be completed by the end of 2005. The units have not been, and will not be, registered under United States securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

For information on subsequent events related to common stock, debt and credit facilities, discontinued operations and assets held for sale, regulatory matters, and related party transactions, see Notes 3, 6, 13, 16, and 19 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. During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining physical and commercial assets outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result, Duke Energy recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. As of September 30, 2005, there are approximately $150 million of deferred net gains in AOCI related to certain DENA cash flow hedges, which will be recognized over the next twelve months. Duke Energy plans to retain the midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation, and combined with Cinergy’s commercial operations, upon completion of the

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merger with Cinergy in early 2006, will provide a sustainable business model for these assets in the region (see Note 10 to the Consolidated Financial Statements, “Acquisition and Disposition” for further details on the anticipated Cinergy merger).

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

	September 30, 2005 One-Day Impact on Operating Income for 2005(a)		Estimated Average One- Day Impact on Operating Income for Third Quarter 2005(a)		Estimated Average One- Day Impact on Operating Income for the Year 2004(a)		High One-Day Impact on Operating Income for Third Quarter 2005(a)		Low One-Day Impact on Operating Income for Third Quarter 2005(a)
	(in millions)
Calculated DER	$	65	$	4	$	7	$	65	$	1

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

The DER figures above do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”). The DER figures as of and for the third quarter 2005 were impacted by the DENA exit plan and the resulting decision to move the DENA hedges to the mark-to-market portfolio as well as commodity price volatility due to Hurricane Rita. The calculated consolidated DER at September 30, 2005 consists of approximately $60 million related to discontinued operations and approximately $5 million related to continuing operations. As of October 31, 2005, the calculated consolidated DER has decreased to approximately $30 million due to actions taken to mitigate open positions in the portfolio.

Credit Risk

Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations.

Duke Energy’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada, Asia Pacific and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

The following table represents Duke Energy’s distribution of unsecured credit exposure with the largest 30 enterprise credit exposures at September 30, 2005. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.

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Distribution of Largest 30 Enterprise Credit Exposures

As of September 30, 2005

	% of Total
Investment Grade—Externally Rated	79	%
Non-Investment Grade—Externally Rated	10	%
Investment Grade—Internally Rated	9	%
Non-Investment Grade—Internally Rated	2	%
Total	100	%

“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Energy utilizes appropriate rating methodologies and credit scoring models to develop a public rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 95% of the gross fair value of Duke Energy’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheet at September 30, 2005.

Duke Energy had net exposure to a single customer that represented greater than 10% of the gross fair value of trade accounts receivable, energy trading assets and derivative assets at September 30, 2005. This customer is externally rated above investment grade. Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its financial position or results of operations as a result of non-performance by any counterparty.

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 September 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. However, there have been no changes in internal control over financial reporting that occurred during the third 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 third quarter of 2005, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 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 Third Quarter of 2005

Period	Total Number of Shares (or Units) Purchased	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares (or Units) that May Yet Be Purchased Under Plans or Programs(a) (in billions)
July 1 to July 31	—	$	—	—	$	1.6
August 1 to August 31	7,518	$	28.71	—	$	1.6
September 1 to September 30	—	$	—	—	$	1.6
Total	7,518	$	28.71	—	$	1.6

(a) On February 24, 2005, Duke Energy announced plans to execute up to approximately $2.5 billion in common stock repurchases over the next three years. On May 9, 2005, in connection with the proposed merger with Cinergy, Duke  Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed (see Note 10 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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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	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. (filed with Form 10-Q of the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 2.1.1)
2.2	Amendment No. 2 to the Agreement and Plan of Merger, dated October 3, 2005, by and among the registrant, Cinergy Corp., Duke Energy Holding Corp., Deer Acquisition Corp., and Cougar Acquisition Corp. (filed with Form 8-K of the registrant dated October 7, 2005, File No. 1-4928, as Exhibit 2.1)
10.1	Second Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC dated as of July 11, 2005 (filed with Form 10-Q of the registrant for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.4.2)
10.2**	Form of Change in Control Agreement between Duke Energy Corporation and certain key executives dated as of July 1, 2005 (filed with Form 8-K of the registrant dated August 24, 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: November 9, 2005	/S/    DAVID L. HAUSER
	David L. Hauser Group Vice President and Chief Financial Officer
Date: November 9, 2005	/S/    STEVEN K. YOUNG
	Steven K. Young Vice President and Controller

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