Duke Energy 10Q 2006 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006 Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-32853

DUKE ENERGY CORPORATION

(Formerly Duke Energy Holding Corp.)

(Exact Name of Registrant as Specified in its Charter)


Delaware		20-2777218
(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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesx No¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filerx Accelerated filer¨ Non-accelerated filer¨

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, par value $0.001, outstanding as of November 3, 2006		1,255,275,068

INDEX

DUKE ENERGY CORPORATION

FORM 10-Q FOR THE QUARTER ENDED

SEPTEMBER 30, 2006


Item		Page
PART I. FINANCIAL INFORMATION

1.	Financial Statements	3
	Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2006 and 2005	3
	Unaudited Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	4
	Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005	6
	Unaudited Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) for the Nine Months Ended September 30, 2006 and 2005	7
	Notes to Unaudited Consolidated Financial Statements	8

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	57

3.	Quantitative and Qualitative Disclosures About Market Risk	84

4.	Controls and Procedures	86

PART II. OTHER INFORMATION

1.	Legal Proceedings	88

1A.	Risk Factors	88

2.	Unregistered Sales of Equity Securities and Use of Proceeds	88

4.	Submission of Matters to a Vote of Security Holders	88

6.	Exhibits	89

	Signatures	90

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•

State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements;

•

Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

•

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

•

Additional competition in electric or gas markets and continued industry consolidation;

•

Political and regulatory uncertainty in other countries in which Duke Energy conducts business;

•

The influence of weather and other natural phenomena on company operations, including the economic, operational and other effects of hurricanes and ice storms;

•

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

•

Unscheduled generation outages, unusual maintenance or repairs and electric transmission or gas pipeline system constraints;

•

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 credit worthiness of counterparties to Duke Energy’s transactions;

•

Employee workforce factors, including the potential inability to attract and retain key personnel;

•

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

•

The performance of electric generation, pipeline and gas processing facilities and of projects undertaken by Duke Energy’s non-regulated businesses;

•

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

•

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

•

The ability to successfully complete merger, acquisition or divestiture plans, such as the announced spin-off of the natural gas transmission businesses, including the prices at which Duke Energy is able to sell assets; 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

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)

Item 1.

Financial Statements.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006			2005
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	958	$	672		$	2,540		$	6,877
Regulated electric		2,402		1,614			5,717			4,099
Regulated natural gas and natural gas liquids		814		742			3,091			2,654
Total operating revenues		4,174		3,028			11,348			13,630
Operating Expenses
Natural gas and petroleum products purchased		235		316			1,404			5,679
Operation, maintenance and other		1,124		777			3,076			2,479
Fuel used in electric generation and purchased power		1,112		488			2,482			1,229
Depreciation and amortization		563		406			1,523			1,349
Property and other taxes		214		134			564			432
Impairment and other charges		—		17			—			140
Total operating expenses		3,248		2,138			9,049			11,308
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		30		63			201			117
Gains on Sales of Other Assets and Other, net		247		580			269			589
Operating Income		1,203		1,533			2,769			3,028
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		195		176			564			256
(Losses) Gains on sales and impairments of equity investments		—		(20	)		(20	)		1,225
Gain on sale of subsidiary stock		15		—			15			—
Other income and expenses, net		83		(40	)		140			19
Total other income and expenses		293		116			699			1,500

Interest Expense		337		228			925			813
Minority Interest Expense		20		10			50			508
Earnings From Continuing Operations Before Income Taxes		1,139		1,411			2,493			3,207
Income Tax Expense from Continuing Operations		422		487			855			1,095
Income From Continuing Operations		717		924			1,638			2,112
Income (Loss) From Discontinued Operations, net of tax		46		(883	)		(162	)		(894	)
Net Income		763		41			1,476			1,218

Dividends and Premiums on Redemption of Preferred and Preference Stock		—		3			—			7
Earnings Available For Common Stockholders	$	763	$	38		$	1,476		$	1,211

Common Stock Data
Weighted-average shares outstanding
Basic		1,254		926			1,141			936
Diluted		1,263		964			1,162			973
Earnings per share (from continuing operations)
Basic	$	0.57	$	0.99		$	1.43		$	2.25
Diluted	$	0.56	$	0.96		$	1.41		$	2.17
Earnings (Loss) per share (from discontinued operations)
Basic	$	0.04	$	(0.95	)	$	(0.14	)	$	(0.96	)
Diluted	$	0.04	$	(0.92	)	$	(0.14	)	$	(0.92	)
Earnings per share
Basic	$	0.61	$	0.04		$	1.29		$	1.29
Diluted	$	0.60	$	0.04		$	1.27		$	1.25
Dividends per share	$	—	$	—		$	0.94		$	0.86

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	September 30, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	820	$	511
Short-term investments		2,097		632
Receivables (net of allowance for doubtful accounts of $103 at September 30, 2006 and $127 at December 31, 2005)		1,969		2,580
Inventory		1,243		863
Assets held for sale		1,395		1,528
Unrealized gains on mark-to-market and hedging transactions		70		87
Other		588		1,756
Total current assets		8,182		7,957
Investments and Other Assets
Investments in unconsolidated affiliates		2,512		1,933
Nuclear decommissioning trust funds		1,666		1,504
Goodwill		8,212		3,775
Intangibles, net		981		65
Notes receivable		221		138
Unrealized gains on mark-to-market and hedging transactions		151		62
Assets held for sale		653		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005)		—		1,281
Other		3,115		2,678
Total investments and other assets		17,511		15,033
Property, Plant and Equipment
Cost		57,538		40,823
Less accumulated depreciation and amortization		16,735		11,623
Net property, plant and equipment		40,803		29,200
Regulatory Assets and Deferred Debits
Deferred debt expense		325		269
Regulatory assets related to income taxes		1,377		1,338
Other		2,084		926
Total regulatory assets and deferred debits		3,786		2,533
Total Assets	$	70,282	$	54,723

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

(In millions, except per-share amounts)


	September 30, 2006		December 31, 2005
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,225	$	2,431
Notes payable and commercial paper		932		83
Taxes accrued		687		327
Interest accrued		312		230
Liabilities associated with assets held for sale		848		1,488
Current maturities of long-term debt		1,637		1,400
Unrealized losses on mark-to-market and hedging transactions		145		204
Other		1,491		2,255
Total current liabilities		7,277		8,418
Long-term Debt		18,678		14,547
Deferred Credits and Other Liabilities
Deferred income taxes		6,960		5,253
Investment tax credit		178		144
Unrealized losses on mark-to-market and hedging transactions		111		10
Liabilities associated with assets held for sale		418		2,085
Asset retirement obligations		2,221		2,058
Other		7,132		5,020
Total deferred credits and other liabilities		17,020		14,570
Commitments and Contingencies
Minority Interests		811		749
Common Stockholders’ Equity
Common stock, $0.001 par value, 2 billion shares authorized; 1,255 million and zero shares outstanding at September 30, 2006 and December 31, 2005, respectively		1		—
Common stock, no par, 2 billion shares authorized; zero and 928 million shares outstanding at September 30, 2006 and December 31, 2005, respectively		—		10,446
Additional paid-in capital		19,775		—
Retained earnings		5,670		5,277
Accumulated other comprehensive income		1,050		716
Total common stockholders’ equity		26,496		16,439
Total Liabilities and Common Stockholders’ Equity	$	70,282	$	54,723

See Notes to Unaudited Consolidated Financial Statements

PART 1

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Nine Months Ended September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,476		$	1,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,652			1,463
Gains on sales of investments in commercial and multi-family real estate		(201	)		(117	)
Gains on sales of equity investments and other assets		(333	)		(1,279	)
Impairment charges		20			123
Deferred income taxes		204			(252	)
Minority Interest		50			508
Equity in earnings of unconsolidated affiliates		(564	)		(256	)
Purchased capacity levelization		(12	)		(12	)
Contributions to company-sponsored pension plans		(159	)		(32	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		24			922
Receivables		1,341			22
Inventory		96			(131	)
Other current assets		1,362			(997	)
Increase (decrease) in
Accounts payable		(1,879	)		(276	)
Taxes accrued		153			611
Other current liabilities		(958	)		817
Capital expenditures for residential real estate		(322	)		(276	)
Cost of residential real estate sold		143			159
Other, assets		625			(76	)
Other, liabilities		22			365
Net cash provided by operating activities		2,740			2,504
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(2,285	)		(1,662	)
Investment expenditures		(82	)		(21	)
Acquisitions, net of cash acquired		(89	)		(293	)
Cash acquired from acquisition of Cinergy		147			—
Purchases of available-for-sale securities		(23,022	)		(30,454	)
Proceeds from sales and maturities of available-for-sale securities		21,419			29,801
Net proceeds from the sales of equity investments and other assets,
and sales of and collections on notes receivable		2,049			2,366
Proceeds from the sales of commercial and multi-family real estate		254			185
Settlement of net investment hedges and other investing derivatives		(134	)		(244	)
Purchases of emission allowances		(182	)		(18	)
Sales of emission allowances		161			—
Other		29			(15	)
Net cash used in investing activities		(1,735	)		(355	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		1,832			286
Issuance of common stock and common stock related to employee benefit plans		67			36
Payments for the redemption of:
Long-term debt		(1,186	)		(1,021	)
Preferred stock of a subsidiary		(12	)		—
Decrease in cash overdrafts		(2	)		—
Notes payable and commercial paper		136			150
Distributions to minority interests		(268	)		(576	)
Contributions from minority interests		219			528
Dividends paid		(1,083	)		(812	)
Repurchase of common shares		(500	)		(933	)
Proceeds from Duke Energy Income Fund		104			—
Other		19			34
Net cash used in financing activities		(674	)		(2,308	)
Changes in cash and cash equivalents included in assets held for sale		(22	)		3
Net increase (decrease) in cash and cash equivalents		309			(156	)
Cash and cash equivalents at beginning of period		511			533
Cash and cash equivalents at end of period	$	820		$	377

Supplemental Disclosures
Acquisition of Cinergy Corp.
Fair value of assets acquired	$	17,306		$	—
Liabilities assumed	$	12,662		$	—
Issuance of common stock	$	8,993		$	—
Significant non-cash transactions:
Conversion of convertible notes to stock	$	632		$	—
AFUDC—equity component	$	42		$	19

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In millions)


												Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Common Stock			Additional Paid-in Capital			Retained Earnings			Foreign Currency Adjustments		Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other		Total
Balance December 31, 2004	957		$	11,266		$	—		$	4,525		$	540	$	526		$	(416	)	$	—	$	16,441
Net income	—			—			—			1,218			—		—			—			—		1,218
Other Comprehensive Income
Foreign currency translation adjustments (a)	—			—			—			—			365		—			—			—		365
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		401			—			—		401
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		(876	)		—			—		(876	)

Total comprehensive income																							1,108
Dividend reinvestment and employee benefits	3			77			—			—			—		—			—			—		77
Stock repurchase	(34	)		(933	)		—			—			—		—			—			—		(933	)
Common stock dividends	—			—			—			(805	)		—		—			—			—		(805	)
Preferred and preference stock dividends	—			—			—			(7	)		—		—			—			—		(7	)
Other capital stock transactions, net	—			—			—			33			—		—			—			—		33

Balance September 30, 2005	926		$	10,410		$	—		$	4,964		$	905	$	51		$	(416	)	$	—	$	15,914

Balance December 31, 2005	928		$	10,446		$	—		$	5,277		$	846	$	(87	)	$	(60	)	$	17	$	16,439
Net income	—			—			—			1,476			—		—			—			—		1,476
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			294		—			—			—		294
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		6			—			—		6
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		25			—			—		25
Other (d)	—			—			—			—			—		—			—			9		9

Total comprehensive income																							1,810
Retirement of old Duke Energy shares	(927	)		(10,399	)		—			—			—		—			—			—		(10,399	)
Issuance of new Duke Energy shares	927			1			10,398			—			—		—			—			—		10,399
Common stock issued in connection with Cinergy merger	313			—			8,993			—			—		—			—			—		8,993
Conversion of Cinergy options to Duke Energy options	—			—			59			—			—		—			—			—		59
Dividend reinvestment and employee benefits	4			22			93			—			—		—			—			—		115
Stock repurchase	(17	)		(69	)		(431	)		—			—		—			—			—		(500	)
Common stock dividends	—			—			—			(1,083	)		—		—			—			—		(1,083	)
Conversion of debt to equity	27			—			632			—			—		—			—			—		632
Tax benefit due to conversion of debt to equity	—			—			34			—			—		—			—			—		34
Other capital stock transactions, net	—			—			(3	)		—			—		—			—			—		(3	)

Balance September 30, 2006	1,255		$	1		$	19,775		$	5,670		$	1,140	$	(56	)	$	(60	)	$	26	$	26,496

(a)

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

(b)	Net unrealized gains on cash flow hedges, net of $2 tax benefit and $230 tax expense for the nine months ended September 30, 2006 and 2005, respectively.

(c)

Reclassification into earnings from cash flow hedges, net of $18 tax expense and $501 tax benefit for the nine months ended September 30, 2006 and 2005, respectively. Reclassification into earnings from cash flow hedges for the nine months ended September 30, 2005 is primarily due to the recognition of Duke Energy North America's (DENA) unrealized net gains related to hedges on forecasted transactions that will no longer occur as a result of the sale to LS Power of substantially all of DENA's assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 13 and 15).

(d)	Net of $4 tax expense for the nine months ended September 30, 2006.

See Notes to Unaudited Consolidated Financial Statements

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 an energy company located in the Americas. 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.

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the three and nine months ended September 30, 2005 and the financial position of Old Duke Energy as of December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy herein.

Shares of common stock of New Duke Energy carry a stated par value of $0.001, while shares of common stock of Old Duke Energy had been issued at no par. In April 2006, as a result of the conversion of all outstanding shares of Old Duke Energy common stock to New Duke Energy common stock, the par value of the shares issued was recorded in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets and the excess of issuance price over stated par value was recorded in Additional Paid-in Capital within Common Stockholders’ Equity in the Consolidated Balance Sheets. Prior to the conversion of common stock from shares of Old Duke Energy to New Duke Energy, all proceeds from issuances of common stock were solely reflected in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present Duke Energy’s financial position and results of operations. Amounts reported in the interim Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors. These Consolidated Financial Statements and other information included in this quarterly report should be read in conjunction with the Consolidated Financial Statements and Notes in Duke Energy’s Form 10-K for the year ended December 31, 2005.

On September 7, 2006, Duke Energy deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership and its inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.

Effective July 1, 2005, Duke Energy deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 2). DEFS has been accounted for as an equity method investment since July 1, 2005.

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

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Reclassifications.As discussed further in Note 14, as a result of the merger with Cinergy, effective in the second quarter of 2006, Duke Energy adopted new business segments and certain prior period amounts have been recast to conform to the new segment presentation. Certain other prior period amounts within the Consolidated Statements of Operations and Consolidated Statements of Cash Flows have been reclassified to conform to the presentation for the current period.

Accounting For Sales of Stock by a Subsidiary. Duke Energy accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain on the sale of stock of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the shares. Duke Energy has elected to treat such excesses as gains in earnings, which are reflected in Gain on Sale of Subsidiary Stock in the Consolidated Statements of Operations. During the three and nine months ended September 30, 2006, Duke Energy recognized a gain of approximately $15 million related to the sale of securities of the Duke Energy Income Fund (Income Fund) (see Note 19).

Accounting For Purchases and Sales of Emission Allowances.Duke Energy recognizes emission allowances in earnings as they are consumed or sold. Gains or losses on sales of emission allowances for non-regulated businesses are presented on a net basis in Gains on Sales of Other Assets and Other, net, in the accompanying Consolidated Statements of Operations. For regulated businesses that do provide for direct recovery of emission allowances, any gains or losses on sales of recoverable emission allowances are included in the rate structure of the regulated entity and are deferred as a regulatory asset or liability. Future rates charged to retail customers are impacted by any gain or loss on sales of recoverable emission allowances and, therefore, as the recovery of the gain or loss is recognized in operating revenues, the regulatory asset or liability related to the emission allowance activity is recognized as a component of Fuel Used in Electric Generation and Purchased Power in the Consolidated Statements of Operations. For regulated businesses that do not provide for direct recovery of emission allowances through a cost tracking mechanism, gains and losses on sales of emission allowances are included in Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations, or are deferred, depending on level of regulatory certainty. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows.

Excise Taxes. Certain excise taxes levied by state or local governments are collected by Duke Energy from its customers. These taxes, which are required to be paid regardless of Duke Energy’s ability to collect from the customer, are accounted for on a gross basis. When Duke Energy acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Duke Energy’s excise taxes accounted for on a gross basis and recorded as revenues in the accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2006 and 2005 were as follows:


	Three Months Ended September 30, 2006		Three Months Ended September 30, 2005		Nine Months Ended September 30, 2006		Nine Months Ended September 30, 2005
	(in millions)
Excise Taxes	$	72	$	36	$	163	$	92

2. 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 purchase date. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in Emerging Issues Task Force (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 as additional, requested information is received during the allocation period, which generally does not exceed one year from the consummation date, however, it may be longer for certain income tax items.

Cinergy Merger. On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). For accounting purposes, the effective date of the merger was April 1, 2006. The merger combines the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger provides more regulatory, geographic and weather diversity to Duke Energy’s earnings. See Note 16 for discussion of regulatory impacts of the merger.

The merger has been accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. As a result, the assets and liabilities of Cinergy were recorded at their respective fair values as of April 3, 2006 and the results of Cinergy’s operations are included in the Duke Energy consolidated financial statements beginning as of the effective date of the merger. Except for an adjustment related to pension and other postretirement benefit obligations, as mandated by Statement of Financial

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” the accompanying consolidated financial statements do not reflect any pro forma adjustments related to Cinergy’s regulated operations that are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which are comprised of Duke Energy Ohio, Inc. (Duke Energy Ohio) (formerly The Cincinnati Gas & Electric Company’s (CG&E) regulated transmission and distribution), Duke Energy Indiana, Inc. (Duke Energy Indiana) (formerly PSI Energy, Inc. (PSI)) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky) (formerly The Union Light, Heat and Power Company (ULH&P)). Under the rate setting and recovery provisions currently in place for these regulated operations which provide revenues derived from cost, the fair values of the individual tangible and intangible assets and liabilities are considered to approximate their carrying values.

The fair values of the assets acquired and liabilities assumed are preliminary and are subject to change as valuation analyses are finalized and remaining information on the fair values is received. However, Duke Energy does not currently anticipate any such changes to have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

In connection with the merger, Duke Energy issued 1.56 shares of Duke Energy common stock for each outstanding share of Cinergy common stock, which resulted in the issuance of approximately 313 million shares of Duke Energy common stock. 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 is valued at approximately $9.1 billion and has resulted in preliminary incremental goodwill to Duke Energy of approximately $4.5 billion. The amount of goodwill results from significant strategic and financial benefits of the merger including:

•

increased financial strength and flexibility;

•

stronger utility business platform;

•

greater scale and fuel diversity, as well as improved operational efficiencies for the merchant generation business;

•

broadened electric distribution platform;

•

improved reliability and customer service through the sharing of best practices;

•

increased scale and scope of the electric and gas businesses with stand-alone strength;

•

complementary positions in the Midwest;

•

greater customer diversity;

•

combined expertise; and

•

significant cost savings synergies.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition:

Purchase Price Allocation


	April 3, 2006
	(in millions)
Purchase price	$	9,111

Current assets		2,677
Investments and other assets		1,610
Property, plant and equipment^(a)		10,578
Intangible assets		1,091
Regulatory assets and deferred debits		1,350

Total assets acquired		17,306
Current liabilities		4,088
Long-term debt		4,295
Deferred credits and other liabilities		4,268
Minority interests		11

Net assets acquired		4,644

Preliminary goodwill	$	4,467

(a)	Amounts recorded for regulated property, plant and equipment by Duke Energy on the acquisition date are net of approximately $3,995 million of accumulated depreciation of acquired assets.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Goodwill recorded as of September 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,467 million, none of which is deductible for income tax purposes. Of this amount, approximately $155 million has been allocated to assets held for sale related to the disposition of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (collectively CMT) (see Note 13). The approximate $178 million increase in goodwill from the merger at September 30, 2006 from the June 30, 2006 initial allocation relates primarily to decreases in property, plant and equipment valuations as a result of additional information received after the June 30, 2006 preliminary valuation. The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments are currently in process and are anticipated to be completed during 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, with the majority of the goodwill being allocated to the U.S. Franchised Electric and Gas segment (see Note 9).

The following unaudited consolidated pro forma financial results are presented as if the Cinergy merger had occurred at the beginning of each of the periods presented:

Unaudited Consolidated Pro Forma Results


	Three Months Ended September 30, 2005		Nine Months Ended September 30,
	Three Months Ended September 30, 2005		2006		2005
	(in millions, except per share amounts)
Operating revenues	$	4,286	$	12,936	$	17,198
Income from continuing operations		1,018		1,696		2,324
Net income		150		1,535		1,446
Earnings available for common stockholders		147		1,535		1,439
Earnings per share (from continuing operations)
Basic	$	0.82	$	1.36	$	1.86
Diluted	$	0.80	$	1.34	$	1.81
Earnings per share
Basic	$	0.12	$	1.23	$	1.15
Diluted	$	0.12	$	1.21	$	1.12

Pro forma results for the nine months ended September 30, 2006 include approximately $97 million of charges related to costs to achieve the merger and related synergies, which are recorded within Operating Expenses on the Consolidated Statements of Operations. Pro forma results for the three months ended September 30, 2006 are not presented since the merger occurred prior to the beginning of the period presented and do not include any significant transactions completed by Duke Energy other than the merger with Cinergy. The pre-tax impacts of purchase accounting on the results of operations of Duke Energy are expected to be charges of approximately $100 million during 2006. The pre-tax impacts of purchase accounting on the consolidated results of operations for the three and nine months ended September 30, 2006 was approximately $15 million and $60 million, respectively.

Other Acquisitions.During the first quarter of 2006, Duke Energy International (DEI) closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas (LPG) and natural gas liquids and the generation, transmission and sale of electricity from a 177 megawatt power plant. These acquisitions increased DEI’s ownership in Aguaytia to 66% and resulted in Duke Energy accounting for Aguaytia as a consolidated entity. Prior to the acquisition of this additional interest, Aguaytia was accounted for as an equity method investment.

During the first quarter of 2006, Duke Energy North America (DENA) acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. The assets and liabilities of Bridgeport were included as part of DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see Note 13).

In May 2006, Duke Energy announced an agreement to acquire an approximate 825 megawatt power plant located in Rockingham County, North Carolina, from Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs for the foreseeable future. The transaction, which is anticipated to close in the fourth quarter of 2006, required approvals by the North Carolina Utilities Commission (NCUC) and the Federal Energy Regulatory Commission (FERC). In addition, approval was required from either the

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

U.S. Department of Justice or the U.S. Federal Trade Commission (FTC) under the Hart-Scott-Rodino Antitrust Improvement Act. The FTC approved the transaction on July 20, 2006, and the NCUC approved it on July 25, 2006. Application for FERC approval was filed on July 28, 2006 and on October 31, 2006 the FERC issued an order conditionally authorizing the transaction.

Dispositions.For the three months ended September 30, 2006, the sale of other assets and businesses resulted in approximately $1.6 billion in proceeds and net pre-tax gains of $247 million recorded in Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. For the nine months ended September 30, 2006, the sale of other assets and businesses resulted in approximately $1.6 billion in proceeds and net pre-tax gains of $269 million recorded in Gains on Sales of Other Assets and Other, net on

the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 13, and sales by Crescent prior to deconsolidation which are discussed separately below. Significant sales of other assets during the nine months ended September 30, 2006 are detailed as follows:

•

On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes.

In conjunction with this transaction, Duke Energy has recognized a pre-tax gain on the sale of approximately $250 million which has been classified as a component of Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statement of Operations for the three and nine months ended September 30, 2006. As a result of the Crescent transaction, Duke Energy no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting. Duke Energy’s equity investment in the Crescent JV is approximately $163 million as of September 30, 2006. The proceeds from the sale were recorded on the Consolidated Statements of Cash Flows as follows: approximately $1.2 billion in long-term debt proceeds, net of issuance costs, were classified as Proceeds from the issuance of long-term debt within Financing Activities, and approximately $380 million, which represents cash received from the MS Members net of cash held by Crescent as of the transaction date, were classified as Net proceeds from the sales of and distributions from equity investments and other assets, and sales of and collections on notes receivable within Investing Activities.

•

Natural Gas Transmission’s sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million which was recorded in Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations. In addition, Natural Gas Transmission’s sale of stock, received as consideration for the settlement of a customers’ transportation contract, resulted in proceeds of approximately $24 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain of $24 million, of which approximately $23 million was recorded in Gains on Sales of Other Assets and Other, net and approximately $1 million was recorded in Other Income and Expenses, net in the accompanying Consolidated Statements of Operations (see Note 10).

For the period from July 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $33 million of proceeds and $30 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 period from January 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $254 million of proceeds and $201 million of net pre-tax gains recorded in Gains on Sales of

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales primarily consisted of two office buildings at Potomac Yard in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.

For the three months ended September 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $1 billion in proceeds and pre-tax gains of $580 million recorded in Gains on Sales of Other Assets and Other, net on the 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 on Sales of Other Assets and Other, net and pre-tax gains of $1.2 billion recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets held for sale as of September 30, 2005 and reflected in discontinued operations, both of which are discussed in Note 13, and sales by 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 have been classified as (Losses) Gains on Sales and Impairments of Equity Investments on 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 the TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the 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 $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million, which was recorded in Gains on Sales of Other Assets and Other, net, on 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 included the acquisition of ConocoPhillips’ interest in the Empress System, which is a natural gas processing and NGL marketing business. 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 the impacts of this transaction on certain cash flow hedges. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

•

Additional asset and business sales during the nine months ended September 30, 2005 totaled approximately $26 million in proceeds. These sales resulted in net pre-tax gains of approximately $14 million which were recorded in Gains on Sales of Other Assets and Other, 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 $41 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, on the Consolidated Statements of Operations.

3. 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, as adjusted, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflect the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised, settled or converted into common stock.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following table illustrates Duke Energy’s basic and diluted EPS calculations and reconciles 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, 2006 and 2005.


	Income			Average Shares	EPS
	(in millions, except per-share data)
Three Months Ended September 30, 2006
Income from continuing operations	$	717
Less: Dividends and premiums on redemption of preferred and preference stock		—

Income from continuing operations—basic	$	717		1,254	$	0.57

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		—		5

Income from continuing operations—diluted	$	717		1,263	$	0.56

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 unvested stock, and common stock derivatives				5
Contingently convertible bond		2		33

Income from continuing operations—diluted	$	923		964	$	0.96

Nine Months Ended September 30, 2006
Income from continuing operations	$	1,638
Less: Dividends and premiums on redemption of preferred and preference stock		—

Income from continuing operations—basic	$	1,638		1,141	$	1.43

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		4		17

Income from continuing operations—diluted	$	1,642		1,162	$	1.41

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 unvested stock, and common stock derivatives				4
Contingently convertible bond		6		33

Income from continuing operations—diluted	$	2,111		973	$	2.17

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The increase in weighted-average shares outstanding for the three and nine months ended September 30, 2006 compared to the same periods in 2005 was due primarily to the April 2006 issuance of approximately 313 million shares in conjunction with the merger with Cinergy (see Note 2), the conversion of debt into approximately 27 million shares of Duke Energy common stock during the nine months ended September 30, 2006 (see Note 4), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the nine months ended September 30, 2006 (see Note 4).

As of September 30, 2006 and 2005, approximately 14 million and 17 million, respectively, of options, unvested stock, performance and phantom stock awards 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.

4. Common Stock

In February 2005, Duke Energy announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. In May 2005, Duke Energy suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy had repurchased approximately $933 million of common stock. In the first quarter of 2006, as a result of the March 10, 2006 shareholder approval of the Cinergy merger, Duke Energy’s Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. In June 2006, Duke Energy suspended additional repurchases of Duke Energy common stock under the repurchase plan due to its plan to spin off the natural gas businesses (see “Matters Impacting Future Results” within Natural Gas Transmission’s “Results of Operations” in Item 2, “Management’s Discussion and Analysis of Results of Operations and Financial Condition”). Prior to the June 2006 suspension, Duke Energy repurchased 17.5 million shares for total consideration of approximately $500 million during 2006. The repurchases and corresponding commissions and other fees were recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed.

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. Additionally, Duke Energy entered into a separate open-market purchase plan on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock, of which approximately 2.6 million shares were repurchased prior to the May 2005 suspension of the program at a weighted average price of $28.97 per share. 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 recorded the approximately $25 million paid at settlement in Common Stockholders’ Equity as a reduction in Common Stock. Total consideration paid to repurchase the shares of approximately $933 million, including commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

of Duke Energy common stock. At September 30, 2006, the balance of the convertible debt is approximately $110 million and remains convertible in the fourth quarter of 2006 into approximately 4.7 million shares of Duke Energy common stock as a result of the stock having achieved the specified price threshold during the third quarter.

See Note 2 for discussion of common stock issued in April 2006 as a result of the merger with Cinergy.

Effective in the third quarter 2006, the Board of Directors of Duke Energy approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

5. Stock-Based Compensation

Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Duke Energy previously applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” and provided the required pro forma disclosures of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

Compensation expense for awards with graded vesting provisions is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.” Duke Energy elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the prior periods presented in this Form 10-Q have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).

Duke Energy recorded pre-tax stock-based compensation expense for the three and nine months ended September 30, 2006 and 2005 as follows, the components of which are further described below:


	Three Months Ended September 30				Nine Months Ended September 30
	2006		2005		2006		2005
	(in millions)
Stock Options	$	2	$	—	$	7	$	—
Stock Appreciation Rights		—		—		1		1
Phantom Stock		8		6		28		16
Performance Awards		12		6		24		20
Other Stock Awards		1		—		2		1

Total	$	23	$	12	$	62	$	38

The tax benefit associated with the recorded expense for the nine months ended September 30, 2006 and 2005 was approximately $23 million and $14 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income, cash flows, or basic and diluted earnings per share from the adoption of SFAS No. 123(R).

The following table shows what earnings available for common stockholders, basic earnings per share and diluted earnings per share would have been if Duke Energy had applied the fair value recognition provisions of SFAS No. 123 to all stock-based compensation awards during prior periods.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Pro Forma Stock-Based Compensation


	Three months ended September 30, 2005			Nine months ended September 30, 2005
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	38		$	1,211

Add: stock-based compensation expense included in reported net income, net of related tax effects		8			24
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(8	)		(24	)

Pro forma earnings available for common stockholders, net of related tax effects	$	38		$	1,211
Earnings per share
Basic—as reported	$	0.04		$	1.29
Basic—pro forma	$	0.04		$	1.29
Diluted—as reported	$	0.04		$	1.25
Diluted—pro forma	$	0.04		$	1.25

Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy issues new shares upon exercising or vesting of share-based awards.

Upon the acquisition of Westcoast Energy, Inc (Westcoast), Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.

Upon the acquisition of Cinergy, Duke Energy converted all stock options outstanding under the Cinergy 1996 Long-Term Incentive Compensation Plan and Cinergy Corp. Stock Option Plan to Duke Energy stock options. The exercise price of these options equaled the market price on the date of grant and the maximum option term is 10 years. The vesting periods are generally three years.

Stock Option Activity


	Options (in thousands)		Weighted-Average Exercise Price		Weighted-Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2005	25,506		$	29
Granted^(a)	9,167			24
Exercised	(3,387	)		22
Forfeited or expired	(1,224	)		33

Outstanding at September 30, 2006	30,062			29	4.9	$	138

Exercisable at September 30, 2006	25,160		$	30	4.3	$	100

(a)	Includes 7,289,222 converted Cinergy stock options

On December 31, 2005, Duke Energy had 22 million exercisable options with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was approximately $26 million and $16 million, respectively. Cash received from options exercised during the nine months ended September 30, 2006 was approximately $73 million, with a related tax benefit of approximately $10 million.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

In addition to the conversion of the Cinergy stock options noted above, Duke Energy granted 1,877,646 options (fair value of approximately $10 million based on a Black-Scholes model valuation) during the nine months ended September 30, 2006. There were no options granted during the year ended December 31, 2005. Remaining compensation expense to be recognized for unvested converted Cinergy options was determined using a Black-Scholes model.

Weighted-Average Assumptions for Option Pricing


		2006
Risk-free interest rate⁽¹⁾		4.78%
Expected dividend yield⁽²⁾		4.40%
Expected life⁽³⁾		6.29 yrs.
Expected volatility⁽⁴⁾		24%

(1)	The risk free rate is based upon the U.S. Treasury Constant Maturity rates as of the grant date.

(2)	The expected dividend yield is based upon annualized dividends and the 1-year average closing stock price,

(3)	The expected term of options is derived from historical data.

(4)

Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on the weighted average between Duke and Cinergy historical volatility over the expected life using daily stock prices. Implied volatility is the average for all option contracts with a term greater than six months using the strike price closest to the stock price on the valuation date.

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.

Stock-based performance awards outstanding under the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 1,608,820 shares (fair value of approximately $32 million) in the nine months ended September 30, 2006, and 1,274,780 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the nine months ended September 30, 2005.

Performance Awards

The following table summarizes information about stock-based performance awards outstanding at September 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2005	2,940,768		$	25
Granted	1,608,820			20
Vested	(114,000	)		27
Forfeited	(246,436	)		26
Canceled	—			—

Outstanding at September 30, 2006	4,189,152		$	23

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was approximately $3 million. As of September 30, 2006, Duke Energy had approximately $40 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.3 years.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,147,950 shares (fair value of approximately $33 million) based on the market price of Duke Energy’s common stock at the grant dates in the nine months ended September 30, 2006, and 1,139,690 shares (fair value of approximately $31 million) in the nine months ended September 30, 2005. Converted Cinergy phantom stock awards are paid in cash and are measured and recorded as liability awards.

Phantom Stock Awards

The following table summarizes information about phantom stock awards outstanding at September 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2005	2,517,020		$	25
Granted^(b)	1,180,112			29
Vested	(845,886	)		25
Forfeited	(153,927	)		26
Canceled	—			—

Outstanding at September 30, 2006	2,697,319		$	27

(b)	Includes 32,162 converted Cinergy awards

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was approximately $21 million and $7 million, respectively. As of September 30, 2006, Duke Energy had approximately $32 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.2 years.

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 279,000 shares (fair value of approximately $8 million) based on the market price of Duke Energy’s common stock at the grant dates in the nine months ended September 30, 2006, and 38,000 shares (fair value of approximately $1 million) in the nine months ended September 30, 2005.

Other Stock Awards

The following table summarizes information about other stock awards outstanding at September 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2005	178,337		$	25
Granted^(c)	329,980			28
Vested	(69,610	)		26
Forfeited	—			—
Canceled	—			—

Outstanding at September 30, 2006	438,707		$	27

(c)	Includes 50,980 converted Cinergy awards

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was approximately $2 million and $1 million, respectively. As of September 30, 2006, Duke Energy had approximately $8 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.0 years.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

6. Inventory

Inventory is recorded at the lower of cost or market value, primarily using the average cost method. The increase in inventory at September 30, 2006 as compared to December 31, 2005 is primarily attributable to inventory acquired as part of the merger with Cinergy.

Inventory


	September 30, 2006		December 31, 2005
	(in millions)
Materials and supplies	$	597	$	434
Natural gas		321		269
Coal held for electric generation		284		115
Petroleum products		41		45

Total inventory	$	1,243	$	863

7. Debt and Credit Facilities

As discussed in Note 4, during the second and third quarters of 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold for each respective quarter. During the second and third quarters of 2006, approximately $632 million of debt was converted into approximately 27 million shares of Duke Energy common stock.

Duke Energy’s debt balance increased at September 30, 2006 as compared to December 31, 2005 primarily as a result of the merger with Cinergy (see Note 2).

In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.

In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

In September 2006, prior to the completion of the joint venture transaction of Crescent, as discussed in Note 2, the Crescent JV, Crescent and Crescent’s subsidiaries borrowed approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a cash inflow within Financing Activities on the Consolidated Statements of Cash Flows and were distributed to Duke Energy. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’s Consolidated Balance Sheets.

In September 2006, Union Gas Limited (Union Gas) entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%.

In October 2006, Duke Energy Carolinas issued $150 million in tax-exempt floating-rate bonds. The bonds are structured as variable-rate demand bonds, subject to weekly remarketing and bear a final maturity of 2031. The initial interest rate was set at 3.72%. The bonds are supported by an irrevocable 3-year direct-pay letter of credit and were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Marshall and Belews Creek Steam Stations.

Available Credit Facilities and Restrictive Debt Covenants. In the second quarter of 2006, Duke Energy closed on the syndication of $3.1 billion in revolving credit facilities in the U.S. and 600 million in Canadian dollars. These syndications, which were amendments to and extensions of existing U.S. and Canadian credit facilities, extended the terms of the credit facilities by one year and built in covenant flexibility where appropriate to allow Duke Energy to pursue certain strategic activities, including the separation of the gas and electric businesses. Additionally, terms for the Cinergy’s facilities were conformed to less restrictive Duke covenants.

During the nine months ended September 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $763 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $460 million in bi-lateral credit facilities. The terminations of these credit facilities primarily

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

reflect Duke Energy’s reduced liquidity needs as a result of exiting the DENA business (see Note 13). During October 2006, the $130 million bi-lateral credit facility at Duke Capital was cancelled. In addition, the remaining $120 million bi-lateral facility at Duke Capital was cancelled in November 2006 and reissued at Duke Energy for the same amount with the same terms and conditions.

The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Duke Energy’s debt and 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, 2006, Duke Energy was in compliance with those covenants. In addition, credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

As of September 30, 2006, approximately $479 million of pollution control bonds and approximately $300 million of commercial paper, which are short-term obligations by nature, were classified as long-term debt on the Consolidated Balance Sheets due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. Duke Energy’s credit facilities with non-cancelable terms in excess of one year as of the balance sheet date give Duke Energy the ability to refinance these short-term obligations on a long-term basis.

Credit Facilities Summary as of September 30, 2006 (in millions)


				Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Energy Carolinas, LLC
$500 multi-year syndicated^{(a), (b), (c)}	June 2011
$75 three-year bi-lateral^{(a), (b), (d)}	September 2009
$75 three-year bi-lateral^{(a), (b), (d)}	September 2009
Total Duke Energy Carolinas, LLC		$	650	$	300	$	—	$	300
Duke Capital LLC
$600 multi-year syndicated^{(a), (b), (e)}	June 2010
$130 three-year bi-lateral^{(b), (j)}	October 2007
$120 multi-year bi-lateral^(b)^{, (k)}	July 2009
Total Duke Capital LLC			850		—		310		310
Westcoast Energy Inc.
$180 multi-year syndicated^{(c), (f)}	June 2011		180		—		—		—
Union Gas Limited
$359 364-day syndicated^(g)	June 2007		359		—		—		—
Cinergy Corp.
$2,000 multi-year syndicated^{(a), (b), (h)}	June 2011		2,000		932		16		948

Total⁽ⁱ⁾		$	4,039	$	1,232	$	326	$	1,558

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

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

(c)	In June 2006, credit facility expiration date was extended from June 2010 to June 2011.

(d)	Credit facility executed in September 2006 to replace $150 million bi-lateral facility which expired in September 2006.

(e)	In June 2006, credit facility expiration date was extended from June 2009 to June 2010.

(f)	Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(g)

In June 2006, credit facility was amended to increase the amount from 300 to 400 million Canadian dollars, in addition to extending the maturity from June 2006 to June 2007. It contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75% and an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

(h)	Contains $500 million sub limits each for Duke Energy Ohio and Duke Energy Indiana. In June 2006, the credit facility expiration date was extended from September 2010 to June 2011.

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

(j)	In October 2006, credit facility was cancelled.

(k)	In November 2006, credit facility was cancelled and reissued at Duke Energy for the same amount with the same terms and conditions.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

8. Employee Benefit Obligations

The following tables show the components of the net periodic pension costs (income) for Duke Energy’s U.S. retirement plans and Westcoast Canadian retirement plans. Net periodic pension costs of Cinergy are included in the below tables (Duke Energy U.S.) for the period from the date of acquisition and thereafter.

Components of Net Periodic Pension Costs: Qualified Pension Benefits (Income)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost	$	31		$	14		$	78		$	45
Interest cost on projected benefit obligation		68			39			172			118
Expected return on plan assets		(81	)		(57	)		(218	)		(171	)
Amortization of prior service credit		—			—			(1	)		(1	)
Amortization of loss		13			9			40			26

Net periodic pension costs	$	31		$	5		$	71		$	17

Westcoast
Service cost	$	4		$	2		$	10		$	6
Interest cost on projected benefit obligation		7			7			23			22
Expected return on plan assets		(8	)		(7	)		(24	)		(20	)
Amortization of prior service cost		1			1			1			1
Amortization of loss		2			1			7			3

Net periodic pension costs	$	6		$	4		$	17		$	12

Components of Net Periodic Pension Costs: Non-Qualified Pension Benefits


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in millions)
Duke Energy U.S.
Service cost	$	1	$	1	$	3	$	1
Interest cost on projected benefit obligation		2		2		5		4
Amortization of prior service cost		—		—		1		1
Amortization of net transition asset		—		—		—		1

Net periodic pension costs	$	3	$	3	$	9	$	7

Westcoast
Service cost	$	1	$	1	$	1	$	1
Interest cost on projected benefit obligation		1		1		3		3
Amortization of loss		—		—		1		—

Net periodic pension costs	$	2	$	2	$	5	$	4

Duke Energy’s policy is to fund amounts for U.S. retirement plans on an actuarial basis to provide sufficient assets to meet benefit payments to plan participants. During the three and nine months ended September 30, 2006, Duke Energy contributed approximately $124 million to the legacy Cinergy qualified pension plans. Duke Energy does not anticipate making any additional contributions to its U.S. qualified pension plans during the remainder of 2006.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 $11 million to the Westcoast DB plans for the three month period ended September 30, 2006 and $32 million for the nine months ended September 30, 2006. Duke Energy anticipates that it will make total contributions of approximately $45 million in 2006. Duke Energy has contributed $1 million to the Westcoast DC plans for the three months ended September 30, 2006 and $3 million for the nine months ended September 30, 2006, and anticipates that it will make total contributions of approximately $4 million in 2006.

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

Components of Net Periodic Post-Retirement Benefit Costs (Income)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost benefit	$	3		$	1		$	9		$	4
Interest cost on accumulated post—retirement benefit obligation		17			11			45			34
Expected return on plan assets		(4	)		(4	)		(12	)		(13	)
Amortization of net transition liability		4			4			12			12
Amortization of loss		3			2			8			6

Net periodic post-retirement benefit costs	$	23		$	14		$	62		$	43

Westcoast
Service cost benefit	$	1		$	1		$	3		$	2
Interest cost on accumulated post—retirement benefit obligation		2			2			5			4
Amortization of prior service credit		(1	)		(1	)		(1	)		(1	)
Amortization of loss		1			—			2			1

Net periodic post-retirement benefit costs	$	3		$	2		$	9		$	6

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy expensed employer matching contributions of $18 million for the three months ended September 30, 2006 compared to $14 million for the three months ended September 30, 2005. Duke Energy expensed employer matching contributions of approximately $59 million for the nine months ended September 30, 2006 compared to $48 million for the nine months ended September 30, 2005.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

9. Goodwill and Intangibles

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets” (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 2006. As discussed further in Note 2, in April 2006, Duke Energy and Cinergy consummated the previously announced merger, which resulted in Duke Energy recording goodwill and intangible assets of approximately $5.6 billion. The following table shows the components of goodwill at September 30, 2006:

Changes in the Carrying Amount of Goodwill


	Balance December 31, 2005		Acquisitions^(a)		Other^(b)			Balance September 30, 2006
	(in millions)
Natural Gas Transmission	$	3,512	$	—	$	121		$	3,633
International Energy		256		—		11			267
Crescent^(c)		7		—		(7	)		—
Unallocated^(a)		—		4,467		(155	)		4,312

Total consolidated	$	3,775	$	4,467	$	(30	)	$	8,212

(a)

Goodwill recorded as of September 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,467 million. The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments is currently in process and is anticipated to be completed by the end of 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, with the majority of the goodwill likely relating to the U.S. Franchised Electric and Gas segment (see Note 2).

(b)	Primarily relates to foreign currency translation and approximately $155 million of goodwill allocated to the disposition of CMT (see Note 13).

(c)	Reduction in goodwill at September 30, 2006 reflects the deconsolidation of Crescent in September 2006 (see Note 2).

Intangible Assets

Intangible assets acquired via merger with Cinergy.In April 2006, in connection with the merger with Cinergy, Duke Energy recorded gross intangible assets of approximately $1,091 million, primarily relating to approximately $712 million of emission allowances, approximately $295 million of gas, coal and power contracts and approximately $84 million of other intangible assets.

The carrying amount and accumulated amortization of intangible assets as of September 30, 2006 and December 31, 2005 are as follows:


	September 30, 2006			December 31, 2005			Weighted Average Life
				(in millions)
Emission allowances	$	650		$	24		^(a	⁾
Gas, coal and power contracts		315			23		^(b	⁾
Other		68			23		25

Total gross carrying amount		1,033			70

Accumulated amortization—gas, coal and power contracts		(29	)		(1	)
Accumulated amortization—other		(23	)		(4	)

Total accumulated amortization		(52	)		(5	)

Total intangible assets, net	$	981		$	65

(a)	Emission allowances do not have a contractual term or expiration date.

(b)

Of this balance, approximately $115 million will be amortized on a consumption basis and does not have a definitive life, approximately $155 million will be amortized on a straight line basis over 20 years, and the remaining balance of approximately $45 million will be amortized on a straight line basis over a weighted average life of approximately 14 years.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Emission allowances sold or consumed during the three and nine months ended September 30, 2006 were $150 million and $286 million, respectively. Emission allowances sold or consumed during the three and nine months ended September 30, 2005 were $3 million and $6 million, respectively.

Amortization expense for intangible assets for the three months ended September 30, 2006 and 2005 was approximately $15 million and $1 million, respectively. Amortization expense for intangible assets for the nine months ended September 30, 2006 and 2005 was approximately $31 million and $1 million, respectively.

The table below shows the expected amortization expense for the next five years for intangible assets as of September 30, 2006. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as gas and coal under existing contracts. The amortization amounts discussed below are estimates. Actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, additional intangible acquisitions and other events.


	2007		2008		2009		2010		2011
	(in millions)
Amortization expense	$	198	$	108	$	97	$	236	$	14

In April 2006, Duke Energy recorded an intangible liability in connection with the merger with Cinergy amounting to approximately $113 million associated with the Market Based Standard Service Offer (MBSSO) in Ohio that will be recognized in earnings over the remaining regulatory period, which ends on December 31, 2008. The carrying amount of this intangible liability was approximately $89 million at September 30, 2006. Amortization expense related to the MBSSO is estimated to amount to approximately $5 million for the remainder of 2006, $27 million of income in 2007 and $67 million of income in 2008. Duke Energy also recorded approximately $56 million of intangible liabilities associated with other power sale contracts in connection with the merger with Cinergy. The carrying amount of this intangible liability was approximately $45 million at September 30, 2006. This balance will be amortized to income as follows: $5 million during the remainder of 2006, approximately $17 million in 2007, approximately $6 million in each of the years 2008 through 2010, and approximately $4 million in 2011.

10. Marketable Securities

During the nine months ended September 30, 2006, Duke Energy’s Natural Gas Transmission business unit received shares of stock as consideration for settlement of a customer’s transportation contract. The market value of the equity securities, determined by quoted market prices on the date of receipt, of approximately $23 million is reflected in Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations for the nine months ended September 30, 2006. Subsequent to receipt, these securities were accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” as trading securities. During the nine months ended September 30, 2006, these securities were sold and an additional gain of approximately $1 million was recognized in Other Income and Expenses, net in the Consolidated Statements of Operations for the nine months ended September 30, 2006.

11. Severance

During the period from the effective date of the Cinergy merger through September 30, 2006, Duke Energy accrued approximately $70 million related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 2). Additionally, Duke Energy recorded approximately $38 million in severance liabilities related to legacy Cinergy that was included in goodwill at the merger date. Substantially all of the remaining payments related to this severance program are expected to be made by the end of 2006.

As discussed in Note 13, in June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as associated contracts managed by these companies, to Fortis, a Benelux-based financial services group. As such, results of operations for CMT have been reflected in Income (Loss) from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to September 30, 2006. The sale of CMT was consummated in October 2006 and Duke Energy did not record any material severance liabilities as a result of the disposal.

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

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA terminated approximately 207 employees through the end of the third quarter of 2006. Management anticipates future severance costs related to this exit plan not included in the following table will be immaterial.

Severance Reserve


	Balance at January 1, 2006		Provision/ Adjustments		Cash Reductions			Balance at September 30, 2006
	(in millions)
Natural Gas Transmission	$	3	$	—	$	(1	)	$	2
Other^(b)		28		109		(86	)		51

Total^(a)(c)	$	31	$	109	$	(87	)	$	53

(a)	Of the $109 million in the provision/adjustments column for the nine months ended September 30, 2006, approximately $70 million was recorded as a charge to income, approximately $38 million was recorded in goodwill and approximately $1 million was deferred as a regulatory asset.

(b)	Amounts associated with DENA’s discontinued operations are included as part of Other (see Note 13).

(c)	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. In the second quarter of 2006, International Energy recorded a $55 million other-than-temporary impairment charge related to an investment 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 GCSA expired on October 26, 2006 and a nine month extension was executed on November 2, 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to management’s best estimate of realizable value. The charges consist of a $17 million impairment of the carrying value of the equity method investment, which has been classified within (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations for the nine months ended September 30, 2006, and a $38 million reserve against notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the Consolidated Statements of Operations for the nine months ended September 30, 2006. The facility ownership will transfer to PEMEX in August 2007. The carrying value of the note at September 30, 2006 was $17 million, which is management’s best estimate of the net realizable value of the note receivable from Campeche.

Field Services. During the nine months ended September 30, 2005, the Field Services business unit recorded a charge of approximately $120 million due to the reclassification into earnings of pre-tax unrealized losses from 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. See Note 15 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

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.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

13. Discontinued Operations and Assets Held for Sale

The following table summarizes the results classified as Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.


	Operating Revenues		Operating (Loss) Gain									Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating (Loss) Gain			Income Tax (Benefit) Expense			Operating (Loss) Gain, Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax			Income (Loss) From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended September 30, 2006
Other^(a)	$	22	$	(17	)	$	(10	)	$	(7	)	$	59		$	21		$	38		$	31
Commercial Power		32		12			8			4			14			3			11			15

Total consolidated	$	54	$	(5	)	$	(2	)	$	(3	)	$	73		$	24		$	49		$	46

Three Months Ended September 30, 2005
Other^(a)	$	663	$	(855	)	$	(307	)	$	(548	)	$	(546	)	$	(219	)	$	(327	)	$	(875	)
International Energy		—		(10	)		(1	)		(9	)		—			—			—			(9	)
Crescent		1		1			1			—			2			1			1			1

Total consolidated	$	664	$	(864	)	$	(307	)	$	(557	)	$	(544	)	$	(218	)	$	(326	)	$	(883	)

Nine Months Ended September 30, 2006
Other^(a)	$	511	$	(71	)	$	(19	)	$	(52	)	$	(175	)	$	(63	)	$	(112	)	$	(164	)
International Energy		—		(1	)		(1	)		—			(10	)		(3	)		(7	)		(7	)
Commercial Power		34		1			5			(4	)		8			(5	)		13			9

Total consolidated	$	545	$	(71	)	$	(15	)	$	(56	)	$	(177	)	$	(71	)	$	(106	)	$	(162	)

Nine Months Ended September 30, 2005
Other^(a)	$	1,540	$	(881	)	$	(318	)	$	(563	)	$	(546	)	$	(219	)	$	(327	)	$	(890	)
International Energy		—		(6	)		(1	)		(5	)		—			—			—			(5	)
Crescent		2		1			1			—			2			1			1			1
Field Services		4		—			—			—			—			—			—			—

Total consolidated	$	1,546	$	(886	)	$	(318	)	$	(568	)	$	(544	)	$	(218	)	$	(326	)	$	(894	)

(a)	Other includes the results for DENA’s discontinued operations, which were previously reported in the DENA segment

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005.

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


	September 30, 2006		December 31, 2005
	(in millions)
Current assets	$	1,395	$	1,528
Investments and other assets		523		2,059
Property, plant and equipment, net (a)		130		1,538

Total assets held for sale	$	2,048	$	5,125

Current liabilities	$	848	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		418		2,024

Total liabilities associated with assets held for sale	$	1,266	$	3,573

(a)

Property, plant and equipment, net includes approximately $106 million related to a plant in the U.S. Franchised Electric and Gas segment that is reflected as Assets Held For Sale on the Consolidated Balance Sheets but does not qualify for discontinued operations treatment under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other

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 remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The DENA assets to be divested include:

•

Approximately 6,100 megawatts (MW) of power generation located primarily in the Western and Eastern United States, including 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.

As of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which included approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 11). Approximately $700 million has been incurred from the announcement date through September 30, 2006, of which approximately $230 million was incurred during the nine months ended September 30, 2006, and was recognized in Income (Loss) From Discontinued Operations, net of tax. No material charges were recognized in the three months ended September 30, 2006.

In January 2006, Duke Energy signed an agreement to sell to LS Power DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 MW of power generation located in the Western and Northeast United States. In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million were subject to LS Power obtaining certain state regulatory approvals. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related to the Moss Landing facility previously sold to LS Power. In August 2006, LS Power made an additional payment to DENA of approximately $40 million, which DENA recorded as an additional gain on the sale of assets.

As of September 30, 2006, the DENA exit activities are substantially complete. As of September 30, 2006 and December 31, 2005, DENA’s remaining assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets. At September 30, 2006, contracts with a net fair value of approximately $6 million remain in Assets Held for Sale and represent contracts that have yet to be novated by Barclays Bank PLC (Barclays). Duke Energy has taken all steps necessary to novate these remaining contracts and is awaiting counterparty action. Barclays handles all administrative aspects of the remaining contracts and there are no cash flows to Duke Energy associated with the remaining contracts, nor does Duke Energy have any continuing involvement with the remaining contracts. In connection with the Barclays transaction, Duke Energy entered into a series of Total Return Swaps (TRS) with Barclays, which are accounted for as mark-to-market derivatives. The fair value of the TRS as of September 30, 2006 is a net liability of approximately $6 million, which offsets the net fair value of the underlying contracts. The TRS will be cancelled as the underlying transactions are transferred to Barclays.

In October 2006, DENA recognized an approximate $38 million pre-tax gain on the sale of available-for-sale securities that were included in Assets Held For Sale on the Consolidated Balance Sheets at September 30, 2006.

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

DENA’s Midwestern generation assets have been retained and, therefore, the results of operations for these assets, including related commodity contracts, did not qualify for discontinued operations classification and remain in continuing operations. Additionally, DENA’s Southeastern generation operations, which were sold in 2004, including related commodity contracts, did not meet the requirements for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for Duke Energy Trading and Marketing, LLC (DETM) will continue to be reported in continuing operations until the wind down of these operations is complete.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 (excluding any potential contingent consideration).

Commercial Power

In June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as certain Duke Energy Ohio trading contracts, to Fortis, a Benelux-based financial services group. Results of operations for CMT, as well as certain Duke Energy Ohio trading contracts, have been reflected in Income (Loss) from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to September 30, 2006. In October 2006, the sale transaction was completed. Under the purchase and sale agreement, Fortis purchased CMT at a base price of approximately $210 million. In addition, Fortis paid approximately $200 million for the portfolio of contracts and an amount equal to the estimated net working capital associated with these companies at the time of close. In October 2006, Duke Energy received total pre-tax cash proceeds of approximately $700 million and recorded an approximate $25 million gain on the sale.

In October 2006, in connection with this transaction, Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis, which are accounted for as mark to market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled for each underlying contracts as each is transferred to Fortis. All economic and credit risk associated with the contracts has been transferred to Fortis as of the date of the sale through the TRS.

International Energy

International Energy held a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. In the first quarter of 2006, based on management’s best estimate of recoverability, International Energy recorded an allowance of approximately $19 million ($12 million after tax) against this receivable, which was recorded in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations. This allowance reduced the carrying value of the receivable to approximately $24 million at March 31, 2006. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million write-up ($5 million after tax) of the receivable through a reduction in the valuation allowance, which was recorded in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations during the nine months ended September 30, 2006. In July 2006, International Energy received the settlement proceeds.

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 Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Additionally, Crescent had two commercial properties, which were sold during the fourth quarter of 2005, for which the results of operations were included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

14. Business Segments

In conjunction with the merger with Cinergy, effective with the second quarter of 2006, Duke Energy has adopted new business segments that management believes properly align the various operations of the merged companies with how the chief operating decision maker views the business. Prior period segment information has been retrospectively adjusted to conform to the new segment structure. Accordingly, the Duke Energy reportable business segments are as follows:

•

U.S. Franchised Electric and Gas—consists of Duke Energy Carolinas (regulated electric utility business in North Carolina and South Carolina), and the following legacy Cinergy regulated operations: Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (legacy Cinergy operations collectively known as Duke Energy Midwest)

•

Natural Gas Transmission—segment is the same as former Duke Energy business segment

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

•

Field Services—segment is the same as former Duke Energy business segment

•

Commercial Power—Duke Energy Ohio’s non-regulated generation including DENA’s Midwestern operations (pre-merger included in Other) and Duke Energy Generation Services (formerly Cinergy Solutions)

•

International Energy—consists of Duke Energy International (DEI) and Cinergy’s international equity interest in a gas distribution system

•

Crescent—segment is the same as former Duke Energy business segment

Cinergy, a Delaware corporation organized in 1993, owns all outstanding common stock of its public utility companies, Duke Energy Ohio and Duke Energy Indiana, which are public utilities, as well as other businesses including (a) cogeneration and energy efficiency investments and (b) natural gas and power marketing and trading operations, conducted primarily through CMT, which was sold to Fortis in October 2006 (see Note 13).

Duke Energy Ohio, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through Duke Energy Kentucky, in nearby areas of Kentucky. Its principal lines of business include generation, transmission, and distribution of electricity, the sale of and/or transportation of natural gas, and power marketing and trading.

Duke Energy Indiana, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana. Its primary line of business is generation, transmission, and distribution of electricity.

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.” Prior to the September 2005 announcement of the exiting of the majority of DENA’s businesses, DENA’s operations were considered a separate reportable segment. There is no aggregation within Duke Energy’s defined business segments.

The remainder of Duke Energy’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes DENA’s discontinued operations, certain unallocated corporate costs, including certain costs to achieve related to the merger with Cinergy, certain discontinued hedges, DukeNet Communications, LLC, Duke Energy Merchants, LLC (DEM), DETM, Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned, captive insurance subsidiary, and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD).

On September 7, 2006, Duke Energy deconsolidated Crescent due to a reduction in ownership and its inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.

In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Duke Energy sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP, an unrelated third party (see Note 2).

In July 2005, Duke Energy completed the agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 2). 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.

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.

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 a correction of an immaterial accounting error related to prior periods.

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2005. Management evaluates segment performance based on earnings before interest and taxes (EBIT) from continuing operations, after deducting minority interest expense related to those profits.

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) 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 transactions 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 unaffiliated revenues and expenses in the accompanying Consolidated Financial Statements.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Business Segment Data^(a)


	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization
	(in millions)
Three Months Ended September 30, 2006
U.S. Franchised Electric and Gas	$	2,477		$	5		$	2,482		$	678		$	363
Natural Gas Transmission		870			1			871			303			120
Field Services^(c)		—			—			—			158			—
Commercial Power		494			3			497			57			45
International Energy		238			—			238			68			19
Crescent^(d)		66			—			66			300			1

Total reportable segments		4,145			9			4,154			1,564			548
Other		29			38			67			(111	)		15
Eliminations		—			(47	)		(47	)		—			—
Interest expense		—			—			—			(337	)		—
Interest income and other^(b)		—			—			—			23			—

Total consolidated	$	4,174		$	—		$	4,174		$	1,139		$	563

Three Months Ended September 30, 2005
U.S. Franchised Electric and Gas	$	1,614		$	5		$	1,619		$	606		$	248
Natural Gas Transmission		857			12			869			329			116
Field Services^(c)		—			—			—			701			—
Commercial Power		(25	)		103			78			(11	)		15
International Energy		186			—			186			63			17
Crescent^(d)		105			—			105			120			—

Total reportable segments		2,737			120			2,857			1,808			396
Other		291			(66	)		225			(165	)		10
Eliminations		—			(54	)		(54	)		—			—
Interest expense		—			—			—			(228	)		—
Interest income and other^(b)		—			—			—			(4	)		—

Total consolidated	$	3,028		$	—		$	3,028		$	1,411		$	406

Nine Months Ended September 30, 2006
U.S. Franchised Electric and Gas	$	5,890		$	14		$	5,904		$	1,388		$	953
Natural Gas Transmission		3,325			(1	)		3,324			1,102			361
Field Services^(c)		—			—			—			450			—
Commercial Power		955			5			960			50			114
International Energy		719			—			719			181			56
Crescent^(d)		221			—			221			515			1

Total reportable segments		11,110			18			11,128			3,686			1,485
Other		238			100			338			(343	)		38
Eliminations		—			(118	)		(118	)		—			—
Interest expense		—			—			—			(925	)		—
Interest income and other^(b)		—			—			—			75			—

Total consolidated	$	11,348		$	—		$	11,348		$	2,493		$	1,523

Nine Months Ended September 30, 2005
U.S. Franchised Electric and Gas	$	4,103		$	15		$	4,118		$	1,216		$	743
Natural Gas Transmission		2,732			92			2,824			1,044			339
Field Services^(c)		5,470			60			5,530			1,784			143
Commercial Power		(28	)		155			127			(44	)		45
International Energy		536			—			536			217			48
Crescent^(d)		281			—			281			210			1

Total reportable segments		13,094			322			13,416			4,427			1,319
Other		536			(106	)		430			(452	)		30
Eliminations		—			(216	)		(216	)		—			—
Interest expense		—			—			—			(813	)		—
Interest income and other^(b)		—			—			—			45			—

Total consolidated	$	13,630		$	—		$	13,630		$	3,207		$	1,349

(a)	Segment results exclude results of any discontinued operations.

(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 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 as an equity method investment for periods after June 30, 2005.

(d)	In September 2006, Duke Energy completed a joint venture transaction of Crescent (see Note 2). As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Segment assets in the following table exclude all intercompany assets.

Segment Assets


	September 30, 2006			December 31, 2005
	(in millions)
U.S. Franchised Electric and Gas^(a)	$	29,983		$	18,739
Natural Gas Transmission		19,214			18,823
Field Services		1,455			1,377
Commercial Power^(a)(b)		7,554			1,619
International Energy		3,230			2,962
Crescent^(c)		163			1,507
Unallocated Goodwill^(d)		4,312			—

Total reportable segments		65,911			45,027
Other^(b)		4,409			9,402
Reclassifications^(e)		(38	)		294

Total consolidated assets	$	70,282		$	54,723

(a)	Increase in segment assets primarily attributable to merger with Cinergy

(b)	Includes impacts of the reclassification of DENA’s Midwestern power generating assets from Other to Commercial Power

(c)	Decrease in Crescent segment assets due to the joint venture transaction of Crescent completed in September 2006 and resulting deconsolidation of Crescent (see Note 2). Balance at September 30, 2006 represents Duke Energy’s effective 50% investment in Crescent as a result of the deconsolidation.

(d)

Unallocated Goodwill recorded as of September 30, 2006 resulting from Duke Energy’s merger with Cinergy. The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments is currently in process and is anticipated to be completed by the end of 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, with the majority of the goodwill likely relating to the U.S. Franchised Electric and Gas segment.

(e)	Represents reclassification of federal tax balances in consolidation.

15. Risk Management Instruments

The following table shows the carrying value of Duke Energy’s derivative portfolio as of September 30, 2006, and December 31, 2005.

Derivative Portfolio Carrying Value


	September 30, 2006			December 31, 2005
	(in millions)
Hedging	$	4		$	(17	)
Trading		—			5
Undesignated		(39	)		(53	)

Total	$	(35	)	$	(65	)

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 $847 million of derivative assets and $726 million of derivative liabilities presented as assets and liabilities held for sale at September 30, 2006.

The $14 million change in the undesignated derivative portfolio fair value is due primarily to realized losses on certain contracts held by Duke Energy related to Field Services’ commodity price risk, partially offset by realized MTM gains at DENA and mark-to-market movement due to change in crude oil prices. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Energy has discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $355 million of pre-tax losses were recognized in earnings by Duke Energy during the nine months ended

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

September 30, 2005. These charges have been classified in the accompanying Consolidated Statements of Operations as follows: upon discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges, approximately $130 million of pre-tax losses prior to the deconsolidation of DEFS were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues, and $105 million of pre-tax losses subsequent to the deconsolidation of DEFS were recognized as a component of Other Income and Expenses, net for the nine months ended September 30, 2005. Approximately $20 million and $25 million of realized and unrealized pre-tax gains and losses, respectively, related to these contracts were recognized in earnings by Duke Energy during the three and nine months ended September 30, 2006, respectively, as a component of Other Income and Expenses, net as of a result of Duke Energy’s investment in DEFS being accounted for using the equity method. Cash settlements on these contracts during the nine months ended September 30, 2006 of approximately $134 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, 2006 and December 31, 2005 are collateral assets of approximately $114 million and $1,279 million, respectively, excluding approximately $306 million which is classified as held for sale associated with the announced sale of CMT. Collateral assets represent cash collateral posted by Duke Energy with other third parties. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 are collateral liabilities of approximately $306 million and $708 million, respectively, excluding approximately $41 million which is classified as held for sale primarily associated with the announced sale of CMT. Collateral liabilities represent cash collateral posted by other third parties to Duke Energy. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, which includes structured power and other contracts, Barclays provided DENA cash equal to the net collateral posted by DENA under the contracts. Net cash collateral received by Duke Energy in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 13).

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

Commodity Cash Flow Hedges.Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Energy’s hedging exposures to the price variability of these commodities does not extend beyond one year.

As of September 30, 2006, $28 million of pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

The ineffective portion of commodity cash flow hedges resulted in the recognition of a pre-tax gain of approximately $3 million in the three and nine months ended September 30, 2006, respectively, as compared to a pre-tax gain of approximately $19 million and a pre-tax loss of approximately $11 million in the three and nine months ended September 30, 2005, respectively. The amount recognized for transactions that no longer qualified as cash flow hedges was a pre-tax loss of approximately $67 million as of September 30, 2006 and is reported in Income (Loss) From Discontinued Operations, net of tax. The amount recognized for transactions that no longer qualify as cash flow hedges was a pre-tax gain of approximately $1.2 billion in the three and nine months ended September 30, 2005, and is reported in Income (Loss) From Discontinued Operations, net of tax 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.

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

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fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in an immaterial amount and a pre-tax gain of $7 million in the three and nine months ended September 30, 2006, respectively, as compared to immaterial amounts in the three and nine months ended September 30, 2005, respectively.

Other Derivative Contracts.In connection with the Barclays transaction discussed in Note 13, Duke Energy entered into a series of TRS with Barclays, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. At September 30, 2006, contracts with a net fair value of approximately $6 million remain in Assets Held for Sale and represent contracts that have yet to be novated by Barclays. Duke Energy has taken all steps necessary to novate these remaining contracts and is awaiting counterparty action. Barclays handles all administrative aspects of the remaining contracts and there are no cash flows to Duke Energy associated with the remaining contracts, nor does Duke Energy have any continuing involvement with these contracts. The fair value of the TRS as of September 30, 2006 is a net liability of approximately $6 million, which offsets the net fair value of the underlying contracts. The TRS will be cancelled as the underlying transactions are transferred to Barclays.

In connection with the Fortis transaction discussed in Note 13, Duke Energy entered into a series of TRS with Fortis, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled as the underlying contracts are transferred to Fortis. There are no future cash flows associated with these contracts, nor does Duke Energy have any continuing involvement with these contracts.

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 Income (Loss) From Discontinued Operations, net of tax 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.

16. Regulatory Matters

Regulatory Merger Approvals.As discussed in Note 1 and Note 2, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly formed company, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the Public Utilities Commission of Ohio (PUCO), the Kentucky Public Service Commission (KPSC), the Public Service Commission of South Carolina (PSCSC) and the NCUC required that certain merger related savings be shared with consumers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. The commissions also required Duke Energy Holding Corp., Cinergy, Duke Energy Ohio, Duke Energy Kentucky, and/or Duke Energy Carolinas to meet additional conditions. While the merger itself was not subject to approval by the Indiana Utility Regulatory Commission (IURC), the IURC approved certain affiliate agreements in connection with the merger subject to similar conditions. Key elements of these conditions include:

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The PUCO required that Duke Energy Ohio provide (i) a rate reduction of approximately $15 million for one year to facilitate economic development in a time of increasing rates and market prices (ii) a reduction of approximately $21 million to Duke Energy Ohio’s gas and electric consumers in Ohio for one year, with both credits beginning January 1, 2006. In April 2006, the Office of the Ohio Consumers’ Council (OCC) filed a Notice of Appeal with the Supreme Court of Ohio, requesting the Court remand the PUCO’s merger approval for a full evidentiary hearing. The OCC alleged that the PUCO improperly failed to: (i) set the matter for a full evidentiary hearing; (ii) consider evidence regarding the transfer of certain DENA assets to Duke Energy Ohio; and (iii) lift the stay on discovery. Duke Energy Ohio and the OCC settled this matter and in June 2006, the Court granted the OCC’s motion to dismiss. As of September 30, 2006, Duke Energy Ohio has returned $11 million and $15 million, respectively, on each of these rate reductions.

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The KPSC required that Duke Energy Kentucky provide $8 million in rate reductions to Duke Energy Kentucky customers over five years, ending when new rates are established in the next rate case after January 1, 2008. As of September 30, 2006, Duke Energy Kentucky has returned $1 million to customers on this rate reduction.

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The PSCSC required that Duke Energy Carolinas provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing profit sharing arrangement. Approximately $15 million of the rate reduction has been passed through to customers since the ruling by the PSCSC.

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The NCUC required that Duke Energy Carolinas provide (i) a rate reduction of approximately $118 million for Duke Energy Carolinas’ North Carolina customers through a credit rider to existing base rates for a one-year period following the close of the merger, and (ii) $12 million to support various low income, environmental, economic development and educationally beneficial programs, the cost of which was incurred in the second quarter of 2006. Approximately $28 million of the rate reduction has been passed through to customers since the ruling by the NCUC.

In its order approving Duke Energy’s merger with Cinergy, the NCUC stated that the merger will result in a significant change in Duke Energy’s organizational structure which constitutes a compelling factor that warrants a general rate review. Therefore, as a condition of its merger approval and no later than June 2007, Duke Energy Carolinas is required to file a general rate case or demonstrate that Duke Energy Carolinas’ existing rates and charges should not be changed. This review will be consolidated with the proceeding that the NCUC is required to undertake in connection with the North Carolina clean air legislation to review the company’s environmental compliance costs. The NCUC specifically noted that it has made no determination that the rates currently being charged by Duke Energy Carolinas are, in fact, unjust or unreasonable.

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The IURC required that Duke Energy Indiana provide a rate reduction of $40 million to Duke Energy Indiana customers over a one year period and $5 million over a five year period for low-income energy assistance and clean coal technology. In April 2006, Citizens Action Coalition of Indiana, Inc., an intervenor in the merger proceeding, filed a Verified Petition for Rehearing and Reconsideration claiming that Duke Energy Indiana should be ordered to provide an additional $5 million in rate reduction to customers to be consistent with the terms of the NCUC’s order approving the merger. In May 2006, the IURC denied the petition for rehearing and reconsideration. As of September 30, 2006, Duke Energy Indiana has returned approximately $17 million to customers on this rate reduction.

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The FERC approved the merger without conditions. In January 2006, Public Citizen’s Energy Program, Citizens Action Coalition of Indiana, Inc., Ohio Partners for Affordable Energy and Southern Alliance for Clean Energy requested rehearing of the FERC approval. In February 2006, the FERC issued an order granting rehearing of FERC’s order for further consideration. A decision by FERC is expected in the fourth quarter of 2006.

U.S. Franchised Electric and Gas.Rate Related Information. The NCUC, PSCSC, IURC and KPSC approve rates for retail electric and gas sales within their states. The PUCO approves rates and market prices for retail electric and gas sales within Ohio. The FERC approves rates for electric sales to wholesale customers served under cost-based rates.

NC Clean Air Act Compliance.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 Carolinas, 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 Carolinas, 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). Duke Energy Carolinas’ amortization expense related to this clean air legislation totals approximately $825 million from inception, with approximately $62 million and $85 million recorded in the third quarter of 2006 and 2005, respectively, and approximately $188 million and $241 million recorded for the first nine months of 2006 and 2005, respectively. As of September 30, 2006, cumulative expenditures totaled approximately $717 million, with $291 million incurred for the first nine months of 2006 and $222 million incurred for the first nine months of 2005 and are included in Net Cash Used In Investing Activities on the Consolidated Statements of Cash Flows. In filings with the NCUC, Duke Energy Carolinas has estimated the costs to comply with the legislation as approximately $1.7 billion. Actual costs may be higher or lower than the estimate based on changes in construction costs, final federal and state environmental regulations, including, among other things, the North Carolina Clean Air legislation and the Clean Air Interstate Rule, and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. Any change in compliance costs will be included in future filings with the NCUC.

Duke Energy Indiana Environmental Compliance Case. In November 2004, Duke Energy Indiana applied to the IURC for approval of its plan for complying with SO₂, NO_X, and mercury emission reduction requirements. Duke Energy Indiana also requested approval of cost recovery for certain proposed compliance projects. An evidentiary hearing was held in May 2005. In December 2005, Duke Energy Indiana, the Indiana Office of Utility Consumer Counselor (OUCC), and the Duke Energy Indiana Industrial Group filed a settlement agreement providing for approval of Duke Energy Indiana’s compliance plan, and approval of financing, depreciation, and operation and main - -

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tenance cost recovery. In May 2006, the IURC approved the settlement agreement in its entirety. The approved Settlement Agreement provides for: (1) the construction of Phase 1 Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) projects with estimated expenditures of approximately $1.08 billion, (2) timely recovery of financing, construction, operation and maintenance cost and depreciation associated with the Phase 1 CAIR and CAMR plan, (3) recovery of emission allowances in connection with SO₂, NOx and mercury, (4) accelerated 20 year depreciation rate, (5) timely recovery of Phase 1 plan development and presentation costs and Phase 2 plan development, engineering and pre-construction, and coal and equipment testing costs, and (6) authority to defer post-in-service allowance for funds used during construction (AFUDC), depreciation costs and operation and maintenance cost until applicable costs are reflected in rates.

Duke Energy Ohio Electric Rate Filings.Duke Energy Ohio operates under a Market Based Standard Service Offer (MBSSO) which was approved by the PUCO in November 2004. In March 2005, the OCC appealed the Commission’s approval of the MBSSO to the Supreme Court of Ohio. The Supreme Court of Ohio recently ruled on the MBSSO’s for two other Ohio utilities, and in each of those rulings, upheld the market prices charged by the utility to its consumers as approved by the Commission but overturned the competitive bid process approved by the Commission on the basis that the Commission rejected the bid price on behalf of consumers and the applicable statute requires customer involvement. Duke Energy Ohio’s MBSSO does not contain a competitive bid process pursuant to a statutory exception. Duke Energy Ohio does not expect a significant, if any, change to its MBSSO as a result of this case but cannot predict the outcome of its case. Duke Energy and Duke Energy Ohio expect the court to decide the case in 2006. On August 2, 2006, Duke Energy Ohio filed an application with the PUCO to extend Duke Energy Ohio’s MBSSO. The proposal provides for continued electric system reliability, a simplified market price structure and clear price signals for customers, while helping to maintain a stable revenue stream for Duke Energy Ohio. The application is pending and Duke Energy Ohio cannot predict the outcome of this proceeding.

Duke Energy Ohio’s MBSSO includes a fuel clause recovery component which is audited annually by the PUCO. In January 2006, Duke Energy Ohio entered into a settlement resolving all open issues identified in the 2005 audit. The PUCO approved the settlement in February 2006. Duke Energy and Duke Energy Ohio do not expect the agreement to have a material impact on their consolidated results of operations, cash flows or financial position.

Duke Energy Ohio filed a distribution rate case to recover certain distribution costs and certain costs that Duke Energy Ohio has deferred in 2004 and 2005 pursuant to its MBSSO. The parties to the proceeding agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $50 million. In December 2005, the PUCO issued an order approving the settlement agreement.

Duke Energy Kentucky Electric Rate Case. In May 2006, Duke Energy Kentucky filed an application for an increase in its base electric rates. The application, which seeks an increase of approximately $67 million in revenue, or approximately 28 percent, to be effective in January 2007 was filed pursuant to the KPSC’s 2003 Order approving the transfer of 1,100 MW of generating assets from Duke Energy Ohio to Duke Energy Kentucky. Duke Energy Kentucky also seeks to reinstitute its fuel cost recovery mechanism which has been frozen since 2001, and has proposed to refresh the pricing for the back-up power supply contract to reflect current market pricing. After Duke Energy Kentucky supplemented its filing in June 2006, the KPSC issued an order in June 2006, shortening the notice period for new rates from 30 to 20 days and suspending rates for six months, until January 6, 2007. Duke Energy Kentucky has reached a settlement agreement in principle with all parties to this proceeding resolving all the issues raised in the proceeding. Among other things, the settlement agreement provides for a $49 million increase in Duke Energy Kentucky’s base electric rates. The KPSC is expected to render a decision on the settlement agreement during the fourth quarter of 2006. At the present time, Duke Energy and Duke Energy Kentucky cannot predict the outcome of this matter.

Duke Energy Kentucky Gas Rate Cases. In 2002, the KPSC approved Duke Energy Kentucky’s gas base rate case which included, among other things, recovery of costs associated with an accelerated gas main replacement program. The approval authorized a tracking mechanism to recover certain costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism as well as the KPSC’s subsequent approval of annual rate adjustments under this tracking mechanism. In 2005, both Duke Energy Kentucky and the KPSC requested that the court dismiss these cases. At the present time, Duke Energy and Duke Energy Kentucky cannot predict the timing or outcome of this litigation.

In February 2005, Duke Energy Kentucky filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism and for a $14 million annual increase in base rates. A portion of the increase is attributable to recovery of the current cost of the accelerated main replacement program in base rates. In December 2005, the KPSC approved an annual rate increase of $8 million

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and re-approved the tracking mechanism through 2011. In February 2006, the Kentucky Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows Duke Energy Kentucky to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows Duke Energy Kentucky to earn a return on investment for the costs recovered under the tracking mechanism which permits Duke Energy Kentucky to recover its gas main replacement costs. At this time, Duke Energy and Duke Energy Kentucky cannot predict the outcome of this litigation.

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

On June 28, 2006, the NCUC issued an order ruling on a dispute between Duke Energy Carolinas, the NCUC Public Staff and the Carolina Utility Customers Association (CUCA) regarding the method for determining the incremental costs of emission allowances used to calculate the BPM Profits under the sharing arrangement. The Public Staff and CUCA each proposed methods that differ from the method intended by Duke Energy Carolinas when it initially requested approval of the sharing arrangement. Duke Energy Carolinas has consistently used its originally intended method since it first implemented the sharing arrangement. The NCUC adopted the Public Staff’s method and ordered Duke Energy Carolinas to file a revised rate rider on June 29, 2006, and to implement the new rider effective July 1, 2006. This ruling resulted in an $18 million charge during the nine months ended September 30, 2006, of which $11 million related to wholesale sales in 2005. On June 29, 2006, Duke Energy Carolinas filed a motion to postpone the effective date of the NCUC’s order to allow time for Duke Energy Carolinas to consider its options and to gather the necessary data to employ the Public Staff’s method and implement a revised rider. The NCUC approved Duke Energy Carolinas’ request on June 30, 2006. On July 17, 2006, Duke Energy Carolinas filed a Motion for Reconsideration requesting that the NCUC reconsider its June 28, 2006 order. In the alternative, Duke Energy Carolinas requested that the NCUC make its order effective only prospectively with respect to sharing periods beginning January 1, 2007. Duke Energy Carolinas also requested that if the NCUC was not inclined to grant its request to reinstate its proposed rider, then the NCUC should approve Duke Energy Carolinas’ withdrawal of the rider at its option. The NCUC heard oral arguments on the Motion on August 29, 2006. On September 15, 2006, Duke Energy Carolinas and the Public Staff filed an Offer of Settlement under which Duke Energy’s method would be used through June 30, 2006 and the Public Staff’s method would be used from July 1, 2006 through the end of the sharing arrangement. Additionally, the sharing arrangement would be extended for the shorter of 1 year (through December 31, 2008) or the effective date of a general rate order from the NCUC addressing the ratemaking treatment of BPM revenues. If approved, the settlement allows Duke Energy Carolinas to reverse the $18 million charge previously recognized. On November 2, 2006, the NCUC ordered this matter set for hearing on January 9, 2007.

Duke Energy Carolinas’ Fuel Factor. On June 27, 2006, the NCUC issued its order approving a fuel factor of 1.6691 cents/kWh for the July 2006 through June 2007 billing period for Duke Energy Carolinas. The approved factor is a 13% increase from the previously approved fuel factor of 1.4769 cents/kWh.

On September 29, 2006, the PSCSC issued its order approving Duke Energy Carolinas’ requested fuel factor of 1.7760 cents/kWh for the October 2006 through September 2007 billing period. The factor was agreed to by all parties to the case and presented to the PSCSC at a hearing on August 24, 2006. The new factor is approximately 12% higher than the current factor of 1.5802 cents/kWh.

Other. U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC) and coal facilities. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. In March 2006, Duke Energy Carolinas announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. With selection of the Cherokee County site, Duke Energy Carolinas is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 MW. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On September 20, 2006, Duke Energy Carolinas filed an application with the NCUC for authority to recover certain

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expenses related to its development and evaluation of the proposed nuclear generation facility (the William States Lee III Nuclear Station). Specifically, Duke Energy Carolinas requests an NCUC order (1) finding that work performed by Duke Energy Carolinas to ensure the availability of nuclear generation by 2016 for its customers is prudent and consistent with the promotion of adequate, reliable, and economical utility service to the citizens of North Carolina and the polices expressed in North Carolina General Statute 62-2, and (2) providing expressly that Duke Energy Carolinas may recover in rates, in a timely fashion, the North Carolina allocable portion of its share of costs prudently incurred to evaluate and develop a new nuclear generation facility through December 31, 2007, whether or not a new nuclear facility is constructed. The application is pending.

On June 2, 2006, Duke Energy Carolinas also filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. The NCUC held public hearings in August 2006, and an evidentiary hearing in Raleigh, North Carolina concluded on September 14, 2006. Post-hearing briefs and proposed orders were filed on October 13, 2006. After the evidentiary hearing, Duke Energy Carolinas received competitive proposals for two major scopes of equipment for the Cliffside Project which suggest that the capital costs for these major components are increasing significantly due to various market pressures that will likely impact utility generation construction projects across the United States. On October 25, 2006, Duke Energy Carolinas filed a Notice of Updated Cost Information informing the NCUC of the increasing cost estimate and requesting that the NCUC issue a CPCN by mid-December 2006. Duke Energy Carolinas also requested that, to the extent the NCUC will require a further evidentiary hearing, such a hearing should be for the limited purpose of receiving evidence as to the new cost information and should be on an expedited basis in order to enable issuance of a CPCN in time to allow commencement of construction on or before April 1, 2007. On November 3, 2006, the NCUC issued an order requiring a further hearing on January 17, 2007 to consider evidence relevant to Duke Energy Carolinas updated cost information for theproject.

In May 2006, Duke Energy Carolinas announced an agreement to acquire an approximate 825 megawatt power plant located in Rockingham County, North Carolina, from Rockingham Power, LLC, an affiliate of Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs for the foreseeable future. The transaction, which is anticipated to close in the fourth quarter of 2006, required approvals by the NCUC and FERC. In addition, approval was required from either the U.S. Department of Justice or the FTC under the Hart-Scott-Rodino Antitrust Improvement Act. The FTC approved the transaction on July 20, 2006, and the NCUC approved it on July 25, 2006. Application for FERC approval was filed on July 28, 2006, and on October 31, 2006 the FERC issued an order conditionally authorizing the transaction.

Duke Energy Indiana filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). Duke Energy Indiana and Vectren reached a Settlement Agreement with the OUCC providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.

On September 7, 2006, Duke Energy Indiana and Vectren filed a joint petition with the IURC seeking certificates of public convenience and necessity for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The petition describes the applicants’ need for additional baseload generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. Duke Energy Indiana and Vectren filed their cases in chief with the IURC on October 24, 2006. A prehearing conference and preliminary hearing is scheduled for November 28, 2006. A hearing on the petition is expected during the first quarter of 2007.

On August 15, 2006, Duke Energy Indiana filed a petition with the IURC requesting recovery of its costs of purchasing electricity to be produced by a 100 megawatt wind energy farm under development pursuant to a 20-year purchased power agreement between Duke Energy Indiana and Benton County Wind Farm, LLC. Duke Energy Indiana and the OUCC have both filed testimony and an evidentiary hearing was conducted before the IURC on October 24, 2006. An order is expected on this case by the end of 2006.

Duke Energy Indiana recovers its actual fuel costs quarterly through a rate adjustment mechanism. In two recent fuel clause proceedings, certain industrial customers and the Citizens Action Coalition of Indiana, Inc. have intervened and sub-dockets have been established to address issues raised by the OUCC and the intervenors concerning the allocation of fuel costs between native load customers and

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non-native load sales, the reasonableness of various Midwest Independent System Operator, Inc. (Midwest ISO) costs for which Duke

Energy Indiana has sought recovery and Duke Energy Indiana’s recovery of costs associated with certain power hedging activities. Duke

Energy Indiana is defending its practices, its costs, and the allocation of such costs. A hearing was conducted in one of these proceedings on September 20, 2006. A decision is not expected before the end of the year. Duke Energy Indiana has been authorized to collect through rates its costs for which it sought recovery in the two sub-docket proceedings, subject to refund pending the outcome of these proceedings. Duke Energy and Duke Energy Indiana cannot predict the outcome of these proceedings but do not expect the outcome to be material to their consolidated results of operations, cash flows or financial position.

Natural Gas Transmission.Rate Related Information. In November 2005, The British Columbia Pipeline System (BC Pipeline) filed an application with the National Energy Board (NEB) for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed and BC Pipeline started negotiations with its shippers to reach a settlement on final tolls for years 2006 and 2007. BC Pipeline reached a toll settlement agreement in principle with its customers for the 2006 and 2007 fiscal years on March 30, 2006. The toll settlement agreement was filed with the NEB on June 21, 2006 and on July 11, 2006 pursuant to the NEB’s Revised Guidelines for Negotiated Settlements, the NEB has asked for comments from interested parties due July 26, 2006. NEB approval was received on August 17, 2006.

Union Gas has rates that are approved by the Ontario Energy Board (OEB). Effective January 1, 2006, Union Gas implemented new rates approved by the OEB in December 2005, reflecting items previously approved. Union Gas’ earnings for 2006 continue to be subject to the earnings sharing mechanism implemented by the OEB in 2005.

In December 2005, Union Gas filed an application with the OEB for new rates effective January 1, 2007. In May 2006, Union Gas reached a comprehensive agreement with intervenors on all financial issues, except storage regulation and Demand Side Management (DSM), and on most non-financial issues. Storage regulation and DSM are being addressed through separate proceedings initiated by the OEB. The OEB accepted this agreement on May 23, 2006. The agreement includes an increase in the common equity component of

Union Gas’ capital structure, from 35% to 36%. A decision on the remaining non-financial issues was issued by the OEB on June 29, 2006. As a result of the comprehensive agreement reached in May 2006, the DSM decision, and the decrease in return on equity, 2007 rates are expected to increase by approximately 1.7%, excluding the impact of the pending decision on storage rates.

Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recover from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the cost incurred.

Effective January 1, 2005, new rates (interim 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. On May 15, 2006 the FERC issued an order approving the settlement agreement. In June 2006, M&N refunded the difference between the settlement rates and the interim rates, plus interest, to each shipper due a refund.

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

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 asso - -

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ciated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina are affected sources under the rule. Six of Cinergy’s eleven coal-fueled generating facilities in which Cinergy is either a whole or partial owner 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 finalized its Clean Air Mercury Rule (CAMR) in May 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 a national emissions allowance trading program. If a state chooses not to participate, then the rule sets a fixed limit on annual mercury emissions from that state’s coal-fired power plants. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation and EPA’s Clean Air Interstate Rule 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 finalized its Clean Air Interstate Rule (CAIR) in May 2005. The rule limits total annual and summertime NOx emissions and annual SO₂ 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 requires region wide SO₂ and NOx emissions to be cut 70 percent and 65 percent, respectively by 2015. The rule gives states the option of participating in the national emissions allowance trading program. If a state chooses not to participate, then the rule sets a fixed limit on the emissions from that state’s affected sources. The emission controls that Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements (see Note 16). Duke Energy currently estimates that it will spend approximately $1.23 billion between 2006 and 2011 to comply with Phase I of the CAIR/CAMR at its Midwest electric operations. The Indiana Utility Regulatory Commission recently issued an order granting Duke Energy approximately $1.08 billion in rate recovery to cover its estimated CAIR/CAMR compliance costs in Indiana (see Note 16). In Ohio, Duke Energy receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its rate stabilization plan. Any remaining costs that Duke Energy might incur to comply with Phase I of the CAIR, such as for the purchase of emission allowances, will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position. Duke Energy 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 $75 million and $55 million as of September 30, 2006 and December 31, 2005, respectively. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites, as well as 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.

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Litigation

New Source Review (NSR)/EPA/Carbon Dioxide 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 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 Fourth Circuit did not reach the question of “routine”. The EPA sought rehearing in the Fourth Circuit, which was denied. On November 1, 2006, oral arguments were made before the U.S. Supreme Court.

In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, Duke Energy Ohio, and Duke Energy Indiana alleging various violations of the CAA. Specifically, the lawsuit alleges that Duke Energy violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review, and Ohio and Indiana SIP permits for various projects at Duke Energy owned and co-owned generating stations. Additionally, the suit claims that Duke Energy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s SIP provisions governing particulate matter at Unit 1 at Duke Energy Ohio’s W.C. Beckjord Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at Duke Energy Ohio’s W.C. Beckjord and Miami Fort Stations, and Duke Energy Indiana’s Cayuga, Gallagher, Wabash River, and Gibson Stations, and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy, Duke Energy Ohio, and Duke Energy Indiana at the trial of the case. Contrary to Cinergy’s, Duke Energy Ohio’s, and Duke Energy Indiana’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals. In August 2006, the Seventh Circuit upheld the district court’s opinion. This issue is before the U.S. Supreme Court in the Duke Energy NSR case, and we do not expect further dispositive legal proceedings in this case until after the Supreme Court ruling.

In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA relating to PSD, NSR, and Ohio State Implementation Plan (SIP) requirements regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and Duke Energy Ohio. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. In April 2001, the United States District Court for the Southern District of Ohio in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision. This matter was heard in trial in July 2005. A decision is pending.

In addition, Cinergy and Duke Energy Ohio have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of PSD, NSR, and Ohio SIP requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and Duke Energy Ohio. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against Duke Energy Ohio, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.

In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by

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Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO₂ from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO₂. The plaintiffs are seeking an injunction requiring each defendant to cap its CO₂emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. Oral argument was held before the Second Circuit Court of Appeals on June 7, 2006.

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 matters.

Western Energy and Natural Gas Litigation and Regulatory Matters. Duke Energy and several of its affiliates, as well as other energy companies, are parties to 34 lawsuits filed by or on behalf of electricity and/or natural gas purchasers in several Western states. Many of the suits seek class-action certification. The plaintiffs allege that the defendants conspired to manipulate 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. Six of these cases were dismissed on filed rate and/or federal preemption grounds, and the plaintiffs in each of these dismissed cases have appealed their respective rulings to the U.S. Ninth Circuit Court of Appeals. In September 2006, Duke Energy reached an agreement in principle to settle the 12 class action cases pending in California. Such agreement is subject to execution of mutually acceptable agreements and approval by the class members and the court. Duke Energy does not expect that the proposed settlement will have a material adverse effect on its consolidated results of operations, cash flows or financial position. With respect to the remaining cases, 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 Duke Energy’s results of operations, cash flows or financial position.

In 2002, Southern California Edison Company initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bi-lateral power contracts between the parties in early 2001. This matter proceeded to hearing in November 2005. In January 2006, the parties reached an agreement in principle to resolve the matters at issue in the arbitration. The parties entered into a Settlement Agreement and Mutual Release dated as of March 10, 2006, and on March 24, 2006, DETM paid the settlement amount, including interest, into escrow. The agreement received final regulatory approval in October 2006. The resolution of this matter did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Trading Related Litigation. 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 and CMT, along with numerous other entities, were named as defendants. 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 certified the class. Duke Energy has reached an agreement with the plaintiffs in these consolidated cases to resolve all issues and on February 8, 2006, the court granted preliminary approval of this settlement. The Final Judgment and Order of Dismissal were entered in May 2006. The resolution of this matter did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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. 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. On September 26, 2005, a petition was filed in state court in Kansas and on May 19, 2006 another petition was filed in Colorado state court. In October 2006, the Missouri Public Service Commission filed a lawsuit in state court in Missouri. These cases were also filed against Duke Energy and DETM, as well as other energy companies. Each of these five cases contains similar claims, that the respective plaintiffs, and the classes they claim to represent, were 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 in violation of the antitrust laws of the respective

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states. Plaintiffs seek damages in unspecified amounts. Duke Energy is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to these matters at this time.

Trading Related Investigations.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 or estimate damages, if any, related to this matter at this time.

Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach, on the other hand, 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 final hearing on damages was concluded in March 2006 and the parties are awaiting a ruling from the tribunal.

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 $190 million (excluding interest). The Court has made preliminary rulings regarding the issues of fact and law that remain for trial. A jury trial is scheduled to commence on December 5, 2006. 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.

Exxon Mobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, Exxon Mobil) filed a Demand for Arbitration against Duke Energy, DETMI Management Inc. (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, Exxon Mobil 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. Exxon Mobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were specified at the arbitration hearing and totaled approximately $125 million (excluding interest). Duke Energy denies these allegations, and has filed counterclaims asserting that Exxon Mobil breached its Venture 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 Exxon Mobil’s claims. Exxon Mobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. Exxon Mobil also filed a motion to dismiss certain of Duke Energy’s counterclaims. Following a hearing in December 2005 on the motion for reconsideration, the arbitrators issued their ruling on January 26, 2006, generally reaffirming the original order, with a limited exception with respect to affiliate trades that is not expected to have a significant impact on the case. The panel also dismissed one of Duke Energy’s counterclaims. The parties agreed that the damages due to Duke Energy on its counterclaim will be determined in the upcoming hearing scheduled in the Canadian arbitration proceedings. The arbitration hearing in the U.S. arbitration was held in October 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain Exxon Mobil entities asserting that those entities wrongfully terminated two gas supply agreements with the DEMLP and wrongfully failed to assume certain related gas supply agreements with other parties. A hearing in the Canadian arbitration was held in March 2006. The arbitrators issued their award in June, 2006 finding that (1) the two gas supply agreements were improperly terminated by ExxonMobil; but (2) ExxonMobil was not required to take assignment of the related third party gas

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supply agreements. A hearing to determine the damages to be paid as the result of the first ruling, as well as the damages to be paid to

Duke Energy as the result of the termination of the U.S. gas supply agreement is scheduled for November 9 and 10, 2006, before the

same panel of arbitrators. At this time Duke Energy is unable to estimate the amount of any damage award to be received in resolution of this matter. The gas supply agreements with other parties, under which DEMLP continues to remain obligated, are currently estimated to result in losses of between $100 million and $150 million through 2011. However, these losses are subject to change in the future in the event of changes in market conditions and underlying assumptions.

Duke Energy Retirement Cash Balance Plan. A class action lawsuit has been filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan, alleging violations of Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Energy Company Employees’ Retirement Plan into the Duke Energy Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions (e.g., the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy filed its answer in March 2006. A second class action lawsuit was filed in federal court in South Carolina, alleging similar claims and seeking to represent the same class of defendants. The second case has been voluntarily dismissed, without prejudice, effectively consolidating it with the first case. 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 this matter.

Hurricane Katrina Lawsuit.In April 2006, Duke Energy and Cinergy were named in the third amended complaint of a purported class action lawsuit filed in the United States District Court for the Southern District of Mississippi. Plaintiffs claim that Duke Energy and Cinergy, along with numerous other utilities, oil companies, coal companies and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. In October 2006, Duke Energy and Cinergy were served with this lawsuit. It is not possible to predict with certainty whether Duke Energy or Cinergy will incur any liability or to estimate the damages, if any, that Duke Energy or Cinergy might incur in connection with this matter.

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas 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.

Duke Energy Indiana and Duke Energy Ohio have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are Duke Energy Indiana cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors. The plaintiffs further claim that as the property owner of the generating stations, Duke Energy Indiana and Duke Energy Ohio should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. The impact on Duke Energy’s financial position, cash flows, or results of operations of these cases to date has not been material.

Of these lawsuits, one case filed against Duke Energy Indiana has been tried to verdict. The jury returned a verdict against Duke Energy Indiana on a negligence claim and a verdict for Duke Energy Indiana on punitive damages. Duke Energy Indiana appealed this

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decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. Duke Energy Indiana paid the judgment of approximately $630,000 in the fourth quarter of 2005. In addition, Duke Energy Indiana has settled over 150 other

claims for amounts, which neither individually nor in the aggregate, are material to Duke Energy Indiana’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.

Duke Energy Ohio has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, Duke Energy is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to Duke Energy.

Other Litigation and Legal Proceedings. Duke Energy and its subsidiaries are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will not have a 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, 2006, Duke Energy has recorded reserves of approximately $1.25 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of September 30, 2006, 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

Cinergy produces synthetic fuel from a facility that qualifies for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code if certain requirements are satisfied. These credits reduce Duke Energy’s income tax liability and therefore Duke Energy’s effective tax rate. Cinergy’s sale of synthetic fuel has generated $339 million in tax credits through December 31, 2005. After reducing for the possibility of phase-outs in 2006, the amount of additional credits generated through September 30, 2006 is immaterial. Section 29/45K provides for a phase-out of the credit if the average price of crude oil during a calendar year exceeds a specified threshold. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices, Duke Energy believes that for 2006 and 2007 the amount of the tax credits will be reduced, perhaps significantly. Through September 2006, oil prices were at a level where Duke Energy had idled the plant, as the value of the credits may not have exceeded the net costs to produce the synthetic fuel during that time period. During the first quarter of 2006, an agreement was in place with the plant operator which would indemnify Duke Energy in the event that tax credits are insufficient to support operating expenses. This agreement did not continue in the second and third quarters of 2006. Duke Energy’s net investment in the plants at September 30, 2006 was approximately $20 million. As a result of the decline in oil prices, the plants began production in October 2006 under a similar indemnification agreement as referenced above.

In August 2006, Duke Energy successfully completed the sale of one of its synthetic fuel facilities resulting in a gain of approximately $6 million. This sale was driven by Internal Revenue Service (IRS) requirements that stipulate that in order to qualify for tax credits in accordance with Section 29/45K, the sales of the synthetic fuel must be made to an unrelated third party.

The IRS has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years including the synthetic fuel facility owned during that period. That facility represents $219 million of tax credits generated during that audit period. The IRS has not proposed any adjustment that would disallow the credits claimed during that period. Subsequent periods are still subject to audit. Duke Energy believes that it operates in conformity with all the necessary requirements to be allowed such credits under Section 29/45K.

Other. As part of its normal business, Duke Energy is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties.

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These arrangements are largely entered into by Duke Capital LLC (Duke Capital). To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy or Duke Capi

tal having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. (For further information see Note 18.)

In addition, Duke Energy enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions. (See Note 18 for discussion of Calpine guarantee obligation).

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.

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, 2006 was approximately $558 million. Of this amount, approximately $318 million relates to guarantees of the payment and performance of less than wholly-owned consolidated entities. Approximately $352 million of the performance guarantees expire between 2006 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.

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 2006 to 2021, 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.

Cinergy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of certain non-wholly-owned consolidated entities. The maximum potential amount of future payments Cinergy could have been required to make under these performance guarantees as of September 30, 2006 was approximately $113 million. Approximately $101 million of the performance guarantees expire between 2009 and 2019, with the remaining performance guarantees having no contractual expiration.

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

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have been required to make under those performance guarantees as of September 30, 2006 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital and Cinergy use 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 or Cinergy 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, 2006 was approximately $50 million. The maximum potential amount of future payments Cinergy could have been required to make under these letters of credit as of September 30, 2006 was approximately $15 million. Substantially all of these letters of credit were issued on behalf of less than wholly-owned consolidated entities and expire in 2006 or 2007.

In connection with Duke Energy’s sale of the Murray merchant generation facility to KGen Partners LLC (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 2006, 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 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, 2006, Duke Capital had guaranteed approximately $200 million of outstanding surety bonds related to obligations of non-wholly-owned entities. The majority of these bonds expire in various amounts in 2007.

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 (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of September 30, 2006 is approximately $200 million, which includes principal and interest. Duke Energy does not believe a loss under the guarantee obligation is probable as of September 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of September 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of September 30, 2006, Natural Gas Transmission was the guarantor of approximately $18 million of debt at Westcoast associated with less than wholly-owned entities, which expire in 2019. International Energy was the guarantor of approximately $13 million of performance guarantees associated with less than wholly-owned entities. Substantially all of these guarantees expire between 2006 and 2008.

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 potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Energy is unable to estimate the total 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, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

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In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist of Duke Energy’s Natural Gas Transmission businesses segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. The businesses remaining in Duke Energy will be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International business segment and Duke Energy’s 50-percent interest in the Crescent JV. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. At September 30, 2006, Duke Energy has certain guarantees of wholly-owned subsidiaries that it expects will become guarantees of third party performance upon the separation of the gas and power businesses. Duke Energy expects to receive back-to-back indemnification from the new gas company indemnifying Duke Energy for any amounts paid related to these guarantees.

19. Related Party Transactions

As discussed in Note 2, in September 2006, Duke Energy deconsolidated its investment in Crescent JV as a result of a reduction in ownership and subsequently has accounted for the investment using the equity method of accounting. Duke Energy’s investment in Crescent JV as of September 30, 2006 was approximately $163 million. Equity earnings for the period from the date of deconsolidated (September 7, 2006) through September 30, 2006 were immaterial. Summary balance sheet information for Crescent, which is accounted for under the equity method, as of September 30, 2006 is as follows:


	September 30, 2006
	(in millions)
Current assets	$	215
Non-current assets	$	1,587
Current liabilities	$	169
Non-current liabilities	$	1,344
Minority interest	$	30

Additionally, as discussed in Note 2, in February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, the general partner of TEPPCO Partners, L.P. (TEPPCO), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO for approximately $100 million. Prior to the completion of these sale transactions, Duke Energy accounted for its investment in TEPPCO under the equity method of accounting. For the three months ended March 31, 2005, TEPPCO had operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61 million, income from continuing operations of approximately $46 million, and net income of approximately $47 million.

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Notes To Consolidated Financial Statements—(Continued)

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% and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners of DEFS. As a result of this transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for the investment using the equity method of accounting (see Note 2). Duke Energy’s 50% of equity in earnings of DEFS for the three and nine months ended September 30, 2006 was approximately $159 million and $454 million, respectively, and Duke Energy’s investment in DEFS as of September 30, 2006 was $1,351 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. Duke Energy’s 50% of equity in earnings of DEFS for the three months ended September 30, 2005 was approximately $126 million. During the three months ended September 30, 2006, Duke Energy had gas sales to and other operating expenses from affiliates of DEFS of approximately $40 million and $3 million, respectively. During the nine months ended September 30, 2006, Duke Energy had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $110 million, $36 million and $24 million, respectively. During the three months ended September 30, 2005, Duke Energy had gas sales to and purchases from affiliates of approximately $28 million and $30 million, respectively. As of September 30, 2006, Duke Energy had payables to affiliates of DEFS of approximately $58 million. Additionally, Duke Energy received approximately $385 million in distributions of earnings from DEFS in the nine months ended September 30, 2006, which are included in Other, assets within Cash Flows from Operating Activities in the accompanying Consolidated Statements of Cash Flows. Duke Energy has recognized an approximate $98 million receivable as of September 30, 2006 due to its share of a distribution declared by DEFS in September 2006 but paid in October 2006. Summary financial information for DEFS, which is accounted for under the equity method, as of and for the three and nine months ended September 30, 2006 is as follows:


	Three months Ended September 30, 2006		Three months Ended September 30, 2005		Nine months Ended September 30, 2006
			(in millions)
Operating revenues	$	3,190	$	3,386	$	9,501
Operating expenses	$	2,841	$	3,105	$	8,492
Operating income	$	349	$	281	$	1,009
Net income	$	318	$	252	$	908


	September 30, 2006
	(in millions)
Current assets	$	2,524
Non-current assets	$	4,759
Current liabilities	$	2,515
Non-current liabilities	$	2,028
Minority interest	$	102

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.

In December 2005, Duke Energy completed a 140 million Canadian dollars initial public offering on its Canadian income trust fund, the Income Fund and sold 14 million Trust Units at an offering price of 10 Canadian dollars per Trust Unit. In January 2006, a subsequent greenshoe sale of 1.4 million additional Trust Units, pursuant to an overallotment option, were sold at a price of 10 Canadian dollars per Trust Unit. Subsequent to the January 2006 sale of additional Trust Units, Duke Energy held an approximate 58% ownership interest in the Income Fund. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of other expenses of issuance, which is included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the Income Fund to approximately 46% at September 30, 2006. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million U.S. Dollar pre-tax SAB No. 51 gain on the sale of subsidiary stock, which is classified in Gain on Sale of Subsidiary Stock on the Consolidated Statements of Operations. The pro - -

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ceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. There were no deferred taxes recorded as a result of this transaction.

Also see Notes 2, 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, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

Statement of Financial Accounting Standards (SFAS) No. 123(R) “Share-Based Payment” (SFAS No. 123(R).In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) 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. For Duke Energy, timing for implementation of SFAS No. 123(R) was January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an acceptable alternative. Instead, Duke Energy is required to determine an appropriate expense for stock options and record compensation expense in the Consolidated Statements of Operations for stock options. Duke Energy implemented SFAS No. 123(R) using the modified prospective transition method, which required Duke Energy to record compensation expense for all unvested awards beginning January 1, 2006.

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy is required to 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, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.

The adoption of SFAS No. 123(R) did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. (See Note 5.)

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” 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 No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring 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.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB No. 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB No. 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) 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 adopted SFAS No. 123(R) and SAB No. 107 effective January 1, 2006.

FASB Interpretation (FIN) No. 47 “Accounting for Conditional Asset Retirement Obligations”(FIN No. 47).In March 2005, the FASB issued FIN No. 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143). 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 obliga - -

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tion under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN No. 47

were effective for Duke Energy as of December 31, 2005, and resulted in an increase in assets of $31 million, an increase in liabilities of $35 million and a net-of-tax cumulative effect adjustment to earnings of approximately $4 million.

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” (FSP No. APB 18-1). In July 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, “The Equity Method of Accounting for Investments in Common Stock” (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 was effective for Duke Energy beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FSP No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event” (FSP No. FAS 123(R)-4).In February 2006, the FASB staff issued FSP FAS No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP No. FAS 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP No. FAS 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP No. FAS 123(R)-4 was effective for Duke Energy as of April 1, 2006. Duke Energy adopted SFAS No. 123(R) as of January 1, 2006 (see Note 5). The adoption of FSP No. FAS 123(R)-4 did not have a material impact on Duke Energy’s consolidated statement of operations, cash flows or financial position.

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (FSP No. FAS 115-1 and 124-1).The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005, which was effective for Duke Energy beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and SFAS No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18. The adoption of FSP No. FAS 115-1 and 124-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FSP No. FIN 46(R)-6, “Determining the Variability to Be Considered In Applying FASB Interpretation No. 46(R) (FSP No. FIN 46(R)-6).”In April 2006, the FASB staff issued FSP No. FIN 46(R)-6 to address how to determine the variability to be considered in applying FIN 46(R), “Consolidation of Variable Interest Entities.” The variability that is considered in applying FIN 46(R) affects the determination of whether the entity is a variable interest entity (VIE), which interests are variable interests in the entity, and which party, if any, is the primary beneficiary of the VIE. The variability affects the calculation of expected losses and expected residual returns. This guidance is effective for all entities with which Duke Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. The adoption of FSP No. FIN 46 (R)-6 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 05-1, “Accounting for the Conversion of an Instrument that Becomes Convertible Upon the Issuer’s Exercise of a Call Option” (EITF No. 05-1).In June 2006, the EITF reached a consensus on EITF No. 05-1. The consensus requires that the issuance of equity securities to settle a debt instrument (pursuant to the instrument’s original conversion terms) that became convertible upon the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contained a substantive conversion feature as of its issuance date. If the debt instrument did not contain a substantive conversion option as of its issuance date, the issuance of equity

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securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus was effective for Duke Energy

for all conversions within its scope that resulted from the exercise of call options beginning July 1, 2006. The adoption of EITF No. 05-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of September 30, 2006:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155).In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (SFAS No. 156).In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157).In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change Duke Energy’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Duke Energy is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position.

SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans,an amendment to of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Duke Energy is required to initially recognize the funded status of its defined benefit pension and other postretirement plans and to provide the required additional disclosures as of December 31, 2006. Retrospective application is not permitted. Duke Energy anticipates that adoption of SFAS No. 158 recognition and disclosure provisions will result in a decrease in total assets of approximately $175 million, an increase in total liabilities of approximately $418 million and a decrease in accumulated other comprehensive income, net of tax, of approximately $593 million as of December 31, 2006. Duke Energy does not anticipate the adoption of SFAS No. 158 will have any material impact on its consolidated results of operations or cash flows.

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Notes To Consolidated Financial Statements—(Continued)

Energy has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. The measurement date requirement is effective for the year ending December 31, 2008, and early application is encouraged. Duke Energy intends to adopt the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. Net periodic benefit cost for the three-month period between September 30, 2006 and December 31, 2006 will be recognized, net of tax, as a separate adjustment of retained earnings as of January 1, 2007, except for any gain or loss arising from curtailments or settlement, if any, during that three-month period, which would be recognized in earnings in 2006. Additionally, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost will be recognized, net of tax, as an adjustment to OCI.

SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement—including the reversing effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

SAB No. 108 is effective for Duke Energy’s year ending December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Duke Energy currently uses a dual approach for quantifying identified financial statement misstatements. Therefore, Duke Energy does not anticipate the adoption of SAB No. 108 will have any material impact on its consolidated results of operations, cash flows or financial position.

FIN No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN No. 48). On July 13, 2006, the FASB issued FIN No. 48, which interprets SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 provides guidance for the recognition, measurement, classification and disclosure of the financial statement effects of a position taken or expected to be taken in a tax return (“tax position”). The financial statement effects of a tax position must be recognized when there is a likelihood of more than 50 percent that based on the technical merits, the position will be sustained upon examination and resolution of the related appeals or litigation processes, if any. A tax position that meets the recognition threshold must be measured initially and subsequently as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Interpretation is effective for Duke Energy as of January 1, 2007. Duke Energy is currently evaluating the impact of adopting FIN No. 48, and cannot currently estimate the impact of FIN No. 48 on its consolidated results of operations, cash flows or financial position.

FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Energy as of January 1, 2007. Duke Energy is currently evaluating the impact of adopting FSP No. FAS 123(R)-5 and cannot currently estimate the impact of adopting FAS 123(R)-5 on its consolidated results of operations, cash flows or financial position.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP No. AUG AIR-1).In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Duke Energy as of January 1, 2007 and will be applied retrospectively for all financial statements presented. Duke Energy does not anticipate the adoption of FSP No. AUG-AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance—Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4” (EITF No. 06-5). In June 2006, the EITF reached a consensus on the accounting for corporate-owned and bank-owned life insurance policies. EITF No. 06-5 requires that a policyholder consider the cash surrender value and any additional amounts to be received under the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Amounts that are recoverable by the policyholder at the discretion of the insurance company must be excluded from the amount that could be realized. Fixed amounts that are recoverable by the policyholder in future periods in excess of one year from the surrender of the policy must be recognized at their present value. EITF No. 06-5 is effective for Duke Energy as of January 1, 2007 and must be applied as a change in accounting principle through a cumulative-effect adjustment to retained earnings or other components of equity as of January 1, 2007. Duke Energy is currently evaluating the impact of adopting EITF No. 06-5, and cannot currently estimate the impact of EITF No. 06-5 on its consolidated results of operations, cash flows or financial position.

21. Income Tax Expense

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of September 30, 2006, Duke Energy has total provisions of approximately $235 million for uncertain tax positions, as compared to approximately $150 million as of December 31, 2005, including interest. The increase in total provisions from year end is primarily attributable to the merger with Cinergy. Duke Energy is also negotiating for Federal Income Tax refunds, including interest, that are not reflected in the financial statements. 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, 2006 was approximately 37.1% as compared to the effective tax rate of 34.5% for the same period in 2005. The increase in the effective tax rate is primarily due to an increase in state taxes as a result of setting up an additional tax reserve attributed to the sale of interest in Crescent. The effective tax rate for the nine months ended September 30, 2006 was approximately 34.3% as compared to the effective tax rate of 34.1% for the same period in 2005. The increase in the effective tax rate was primarily attributable to the increase in state taxes as a result of setting up an additional tax reserve attributed to the sale of interest in Crescent, offset by the reduction in state deferred tax liabilities related to the merger with Cinergy.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

22. Comprehensive Income and Accumulated Other Comprehensive Income

Comprehensive Income. Comprehensive income includes net income and all other non-owner changes in equity. Components of other comprehensive income and accumulated other comprehensive income for the nine months ended September 30, 2006 and 2005 are presented in the Consolidated Statements of Common Stockholder’s Equity.


Total Comprehensive Income (Loss)

	Three Months Ended September 30,
	2006			2005
	(in millions)
Net Income	$	763		$	41

Other comprehensive income
Foreign currency translation adjustments		(17	)		309
Net unrealized gains on cash flow hedges^a		9			165
Reclassification into earnings from cash flow hedges^b		8			(878	)
Other		3			—

Other comprehensive income (loss), net of tax		3			(404	)

Total Comprehensive Income (Loss)	$	766		$	(363	)

^a	Net unrealized gains on cash flow hedges, net of $4 million and $107 million tax expense for the three months ended September 30, 2006 and 2005, respectively.

Reclassification into earnings from cash flow hedges, net of $4 million tax expense and $502 million tax benefit for the three months ended September 30, 2006 and 2005, respectively. Reclassification into earnings from cash flow hedges for the three months ended September 30, 2005, is primarily due to the recognition of Duke Energy North America’s (DENA’s) unrealized net gains on related to hedges on forecasted future transactions that will no longer occur as a result of the sale to LS Power 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).

23. Subsequent Events

PART I

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

INTRODUCTION

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

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC effective October 1, 2006). As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the three and nine months ended September 30, 2005 and the financial position of Old Duke Energy as of December 31, 2005. New Duke Energy had separate operations for the period beginning with the quarter ended June 30, 2006, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the date of acquisition and thereafter.

Executive Overview

In 2006, management of Duke Energy established a goal to achieve a business model that would give both Duke Energy’s electric and gas businesses stand-alone strength and additional scope and scale along with steady and stable earnings growth. So far in 2006, management has executed this strategy primarily through strategically completed and pending acquisitions, as well as dispositions of certain businesses with higher risk profiles, such as the Duke Energy North America (DENA) operations outside the Midwest and the Cinergy commercial marketing and trading businesses.

On April 3, 2006, Duke Energy and Cinergy consummated the previously announced merger, which combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger with Cinergy increased the size and scope of Duke Energy’s electric utility operations. Duke Energy management expects to achieve numerous synergies, both immediately and over time, in all regions impacted by the merger.

In line with giving the electric utility operations more scope and scale, Duke Energy has announced an agreement with Southern Company to evaluate the potential construction of a new nuclear power plant at a site jointly owned in Cherokee County, South Carolina. Additionally, Duke Energy continues to evaluate other opportunities to re-invest in the electric utility operations, by modernizing and expanding older coal-fired plants in the Carolinas and exploring the replacement of an aging coal plant in Indiana with a coal gasification plant. Duke Energy has also announced an agreement to acquire from Dynegy an approximate 825 megawatt power plant located in Rockingham County, North Carolina. The transaction is anticipated to close in the fourth quarter of 2006. This peaking plant, which will primarily be used during times of high electricity demand, generally in the winter and summer months, will provide customers with competitively priced peaking capacity and helps to ensure Duke Energy can meet growing customer demands for electricity in the foreseeable future.

As a result of the additional size and scope of the electric utility operations discussed above, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in Duke Energy Field Services, LLC (DEFS). If completed, the spin off of the natural gas business is expected to deliver long-term value to shareholders as the two stand-alone companies would be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations. It is anticipated that approximately $9 billion of debt currently at Duke Capital LLC (Duke Capital) and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

PART I

The primary businesses remaining in Duke Energy post-spin are anticipated to be principally the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV.

In connection with the effort to reduce the risk profile of Duke Energy and to focus on businesses that can be expected to contribute steady, stable earnings growth, during 2006 Duke Energy has finalized the sale of the former DENA power generation fleet outside of the Midwest to LS Power Equity Partners (LS Power) and agreed to sell the Cinergy commercial marketing and trading business to Fortis, a Benelux-based financial services group (Fortis). The sale to Fortis closed in October 2006 and resulted in Duke Energy receiving approximately $700 million of pre-tax proceeds.

Additionally, the Board of Directors of Duke Energy authorized management to explore the potential value of bringing in a joint venture partner at Crescent to expand the business and create a platform for increased growth. On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Energy and has been classified as a financing activity in the accompanying Consolidated Statement of Cash Flows for the nine months ended September 30, 2006. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of the Crescent JV for financial reporting purposes. In conjunction with this transaction, Duke Energy recognized a pre-tax gain of approximately $250 million on the sale. As a result of the Crescent transaction, Duke Energy no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting.

Proceeds from the sales of the commercial marketing and trading business and Crescent are anticipated to be used to reduce commercial paper outstanding at Cinergy and to partially fund capital expenditure requirements for Duke Energy over the near-term.

Effective with the third quarter 2006, the Board of Directors of Duke Energy has approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share. Additionally, during 2006 Duke Energy has repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the above mentioned plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders, the share repurchase program has been suspended. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed.

For the three months ended September 30, 2006, Duke Energy reported net income of $763 million and diluted earnings per share of $0.60 as compared to net income and diluted earnings per share of $41 million and $0.04, respectively, for the three months ended September 30, 2005. The increase in earnings per share was due primarily to an approximate $0.8 billion after-tax impairment charge (approximately $1.3 billion pre-tax) in 2005 related to DENA, an approximate $250 million pre-tax gain recorded in 2006 on Duke Energy’s sale of 50% of its interest in Crescent and the absence of prior year hedge losses associated with de-designated Field Services’ hedges, partially offset by an approximate $575 million pre-tax gain recorded in 2005 as a result of the DEFS disposition transaction, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% effective July 1, 2005. These results include the impacts of former Cinergy for the quarter ended September 30, 2006.

For the nine months ended September 30, 2006, Duke Energy reported net income of $1,476 million and diluted earnings per share of $1.27 as compared to net income and diluted earnings per share of $1,218 million and $1.25, respectively, for the nine months ended September 30, 2005. These amounts include the results of former Cinergy for the six months ended September 30, 2006. The increase in net income and earnings per share was due primarily to an approximate $0.8 billion after-tax impairment charge (approximately $1.3 billion pre-tax) in 2005 related to DENA, an approximate $250 million pre-tax gain recorded in 2006 on Duke Energy’s sale of 50% of its interest in Crescent and the absence of prior year hedge losses associated with de-designated Field Services’ hedges, partially offset by the pre-tax gains of approximately $900 million (net of minority interest of approximately $343 million) recorded in 2005 related to DEFS’ sale of Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP

PART I

(TEPPCO LP) and Duke Energy’s sale of its limited partner interests in TEPPCO LP, and an approximate $575 million gain recorded in 2005 as a result of the DEFS disposition transaction. Diluted earnings per share for the three and nine months ended September 30, 2006 as compared to the diluted earnings per share for the three and nine months ended September 30, 2005 were negatively impacted by the significant increase in the weighted-average common stock shares outstanding for the three and nine months ended September 30, 2006, primarily as a result of the issuance of approximately 313 million shares in conjunction with the Cinergy merger and the conversion of debt into approximately 27 million shares, partially offset by the repurchase of approximately 17.5 million shares under the share repurchase program.

The highlights for the three and nine months ended September 30, 2006 include:

•

U.S. Franchised Electric and Gas, which is comprised of Duke Energy Carolinas (formerly known as Duke Power) and the regulated portion of the legacy Cinergy utilities located in the Midwest, delivered higher results for the three and nine months ended September 30, 2006 as compared to the same periods in the prior year, due primarily to the inclusion of legacy Cinergy for the three and six months ended September 30, 2006, reduced regulatory amortization expense and customer growth in the service territories, partially offset by lower wholesale power revenues, rate reductions related to merger savings, higher operating and maintenance costs and milder weather;

•

Natural Gas Transmission’s earnings decreased for the three months ended September 30, 2006 compared to the same period in the prior year due primarily to higher operating and maintenance costs, lower earnings on Canadian operations and lower equity earnings related to project financing, partially offset by higher natural gas processing — primarily from the addition of the Empress assets acquired in 2005. For the nine months ended September 30, 2006, Natural Gas Transmission’s earnings increased over the same period in the previous year due to higher natural gas processing — primarily Empress assets, business expansion, favorable resolution of property tax issues and the impact of a strengthening Canadian currency, partially offset by higher operating costs and lower equity earnings related to interest expense;

•

Field Services earnings decreased in 2006 as compared to the same periods in the prior year, primarily as a result of the gain from the sale of TEPPCO in 2005, the gain in 2005 resulting from the DEFS disposition transaction, as well as the impact of the reduction in ownership percentage by Duke Energy as a result of the DEFS disposition transaction, and decreased volumes, partially offset by strong commodity prices during 2006, natural gas liquids (NGL) and gas marketing results and lower hedge losses recognized with the discontinuance of certain cash flow hedges in 2005;

•

Commercial Power, which consists of Duke Energy Ohio, Inc.’s non-regulated generation, including DENA’s Midwest power operations and Duke Energy Generation Services, reported improved earnings over the same periods in the prior year. Improved results were primarily driven by the addition of Cinergy’s non-regulated businesses in the Midwest and improved results from DENA’s power generation assets in the region. These improvements were partially offset by approximately $17 million and $65 million in purchase accounting adjustments recorded during three and six months ended September 30, 2006, respectively, and operating costs associated with Cinergy’s synthetic fuel facilities;

•

International Energy earnings increased for the three months ended September 30, 2006 compared to the same period in the prior year due primarily to an equity investment impairment related to Campeche recorded in the third quarter 2005 and favorable hydrology in Argentina, partially offset by unfavorable hydrology in Peru and Brazil, and an unplanned outage at National Methanol Company (NMC). For the nine months ended September 30, 2006, International Energy experienced lower earnings compared to the same period in the prior year primarily driven by a second quarter 2006 impairment of the Campeche equity investment in Mexico and related note receivable, increased power purchases as a result of an unplanned outage in Peru, unfavorable hydrology in Peru and Brazil, and unplanned outages at NMC. These results were partially offset by favorable hydrology in Argentina and favorable currency impacts—mainly in Brazil;

•

Crescent had improved results compared to same periods in the prior year, driven primarily by the gain recorded in the third quarter 2006 on Duke Energy’s sale of 50% of its interest in Crescent and an approximate $133 million gain on the sales of properties at Potomac Yard in Washington, DC and a land sale at Lake Keowee in South Carolina in the second quarter 2006, partially offset by third quarter 2005 gains of $86 million on the sales of a commercial office building portfolio and legacy land;

•

Other losses decreased for the three months ended September 30, 2006 compared to the same period in the prior year due primarily to impacts of certain discontinued cash flow hedges, offset slightly by charges in 2006 associated with the Cinergy merger and third party costs incurred for the Gas Spin-off. For the nine months ended September 30, 2006, Other losses decreased compared to the same period in the prior year primarily as a result of lower losses on Field Services hedges, the recognition of reserves for estimated property damage related to hurricanes and business interruption losses in 2005, and timing of other captive insurance claims, partially offset by Cinergy merger related costs and third party costs incurred for the Gas Spin-off; and

PART I

•

Income (loss) from discontinued operations, primarily related to the exit of the DENA business, improved in 2006 compared to the same periods in the prior year due primarily to a charge in 2005 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 Duke Energy Trading and Marketing (DETM). The 2006 results reflect the impacts of termination or sale of the final remaining contracts at DENA. Additionally, in the second quarter of 2006, an exit plan for the Cinergy commercial marketing and trading business was announced and 2006 results reflects this portion of the business as discontinued operations subsequent to the date of acquisition.

RESULTS OF OPERATIONS

Results of Operations and Variances


	Three Months Ended September 30,								Nine Months Ended September 30,
	2006		2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	4,174	$	3,028		$	1,146		$	11,348		$	13,630		$	(2,282	)
Operating expenses		3,248		2,138			1,110			9,049			11,308			(2,259	)
Gains on sales of investments in commercial and multi-family real estate		30		63			(33	)		201			117			84
Gains on sales of other assets and other, net		247		580			(333	)		269			589			(320	)

Operating income		1,203		1,533			(330	)		2,769			3,028			(259	)
Other income and expenses, net		293		116			177			699			1,500			(801	)
Interest expense		337		228			109			925			813			112
Minority interest expense		20		10			10			50			508			(458	)

Earnings from continuing operations before income taxes		1,139		1,411			(272	)		2,493			3,207			(714	)
Income tax expense from continuing operations		422		487			(65	)		855			1,095			(240	)

Income from continuing operations		717		924			(207	)		1,638			2,112			(474	)
Income (loss) from discontinued operations, net of tax		46		(883	)		929			(162	)		(894	)		732

Net income		763		41			722			1,476			1,218			258
Dividends and premiums on redemption of preferred and preference stock		—		3			(3	)		—			7			(7	)

Earnings available for common stockholders	$	763	$	38		$	725		$	1,476		$	1,211		$	265

Consolidated Operating Revenues

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating revenues for the three months ended September 30, 2006 increased $1,146 million, compared to the same period in 2005. This change was driven primarily by:

•

An approximate $1,350 million increase due to the merger with Cinergy, and

•

A $52 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $33 million).

Partially offsetting this increase in revenues were:

•

A $158 million decrease in Other due primarily to the continued wind-downs of DETM, Duke Energy Merchants, LLC (DEM) and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD), and a prior year gain related to DENA’s hedge discontinuance in the Southeast (approximately $30 million),

•

An approximate $50 million decrease associated with the DENA Midwest plants due primarily to lower plant production and unfavorable hedge results, and

•

A $39 million decrease at Crescent driven primarily by lower residential developed lot sales, due primarily to decreased sales in Florida.

PART I

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating revenues for the nine months ended September 30, 2006 decreased $2,282 million, compared to the same period in 2005. This change was driven primarily by:

•

A $5,530 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

•

An approximate $203 million decrease in Other due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD, and

•

An approximate $91 million decrease associated with the DENA Midwest plants due primarily to lower plant production and unfavorable hedge results.

Partially offsetting this decrease in revenues were:

•

An approximate $2,653 million increase due to the merger with Cinergy

•

A $500 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $298 million), recovery of higher natural gas commodity costs (approximately $152 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas, and favorable Canadian dollar foreign exchange impacts (approximately $134 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $150 million)

•

A $183 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $81 million), higher energy prices in El Salvador (approximately $41 million), favorable exchange rates in Brazil (approximately $28 million) and higher electricity volumes and prices in Argentina (approximately $25 million), and

•

An approximate $130 million increase in Other related to the prior year impact of the realized and unrealized mark-to-market losses of Field Services’ hedges that had been recorded in operating revenues prior to the deconsolidation of DEFS.

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

Consolidated Operating Expenses

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating expenses for the three months ended September 30, 2006 increased $1,110 million, compared to the same period in 2005. This change was driven primarily by:

•

An approximate $1,135 million increase due to the merger with Cinergy

•

An approximate $81 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs, and increased purchase power expense, due primarily to less generation availability during third quarter of 2006 as a result of outages at base load stations, partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation

•

A $48 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $20 million), and increased purchased power and regulatory fees in Latin America (approximately $30 million), and

•

An approximate $29 million increase in Other associated with costs to achieve the Cinergy merger and the anticipated spin-off of Duke Energy’s natural gas businesses.

Partially offsetting this increase in expenses were:

•

An approximate $143 million decrease in Other due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD, and

•

An approximate $65 million decrease associated with the DENA Midwest plants due primarily to lower plant production and improved fuel hedge results.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating expenses for the nine months ended September 30, 2006 decreased $2,259 million, compared to the same period in 2005. This change was driven primarily by:

•

An approximate $5,087 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

•

An approximate $249 million decrease in Other due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD

PART I

•

An approximate $120 million decrease associated with the prior year 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”), and

•

An approximate $101 million decrease associated with the DENA Midwest plants due primarily to lower plant production and improved fuel hedge results.

Partially offsetting this decrease in expenses were:

•

An approximate $2,327 million increase due to the merger with Cinergy

•

A $467 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily the Empress System (approximately $225 million), increased natural gas prices at Union Gas (approximately $152 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, Canadian dollar foreign exchange impacts (approximately $106 million), partially offset by lower gas purchase costs due to unseasonably warmer weather (approximately $127 million)

•

A $192 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $64 million), an allowance on a note receivable from the Campeche equity investment (approximately $38 million), and higher fuel prices and volumes, and purchased power costs in Latin America (approximately $90 million)

•

An approximate $157 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs, increased operating and maintenance and increased purchase power expense, due primarily to less generation availability during 2006 as a result of outages at base load stations, partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation, and

•

An approximate $114 million increase in Other associated with costs to achieve the Cinergy merger and the anticipated spin-off of Duke Energy’s natural gas businesses.

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, 2006 as Compared to September 30, 2005.Consolidated gains on sales of investments in commercial and multi-family real estate decreased $33 million compared to the same period in 2005. This decrease was driven primarily by a $41 million land sale gain at Catawba Ridge in South Carolina in the third quarter of 2005 compared to lesser activity in the third quarter of 2006.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated gains on sales of investments in commercial and multi-family real estate increased $84 million compared to the same period in 2005. This increase was primarily due to an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale gain at Catawba Ridge in South Carolina in 2005.

Consolidated Gains on Sales of Other Assets and Other, Net

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated gains on sales of other assets and other, net for the three months ended September 30, 2006 decreased $333 million, compared to the same period in 2005. The decrease was due primarily to an approximate $575 million gain recorded in 2005 as a result of the DEFS disposition transaction, partially offset by an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Energy and MSREF.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated gains on sales of other assets and other, net for the nine months ended September 30, 2006 decreased $320 million, compared to the same period in 2005. The decrease was due primarily to an approximate $575 million gain recorded in 2005 as a result of the DEFS disposition transaction, partially offset by an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Energy and MSREF and an approximate $23 million gain on the settlement of a customer’s transportation contract at Natural Gas Transmission in 2006.

PART I

Consolidated Operating Income

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating income for the three months ended September 30, 2006 decreased $330 million, compared to the same period in 2005. Decreased operating income was primarily related to an approximate $575 million gain in 2005 resulting from the DEFS disposition transaction, partially offset by an approximate $250 million gain in 2006 on the sale of a 50% interest in Crescent. Other drivers to operating income are discussed above.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated operating income for the nine months ended September 30, 2006 decreased $259 million, compared to the same period in 2005. Decreased operating income was primarily related to an approximate $575 million gain in 2005 resulting from the DEFS disposition transaction and the impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to approximately $443 million for the nine months ended September 30, 2005 . Partially offsetting these decreases were an approximate $250 million gain in 2006 on the sale of a 50% interest in Crescent, an approximate $250 million negative impact to operating income in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk and approximately $325 million of operating income generated by legacy Cinergy in 2006 as a result of the merger. 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, 2006 as Compared to September 30, 2005. Consolidated other income and expenses, net for the three months ended September 30, 2006 increased $177 million, compared to the same period in 2005. The increase was due primarily to approximately $20 million of mark-to-market gains on DEFS hedges due to decreases in crude oil prices for the three months ended September 30, 2006 as compared to losses of approximately $105 million in the same period in the prior year, an increase of approximately $19 million in equity in earnings of unconsolidated affiliates primarily due to the increased earnings at DEFS, approximately $20 million of impairment charges on equity method investments recorded in the third quarter 2005, primarily International Energy’s investment in Campeche (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”) and a Staff Accounting Bulletin (SAB) No. 51 gain of $15 million in 2006 related to the Duke Energy Income Fund’s (Income Fund) issuance of additional units of the Canadian income trust fund, which resulted in a dilution of Duke Energy’s ownership.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated other income and expenses, net for the nine months ended September 30, 2006 decreased $801 million, compared to the same period in 2005. The decrease was due primarily to the $1,245 million pre-tax gains on sales of equity investments recorded in 2005, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, as discussed above, partially offset by an increase of approximately $308 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005 and an approximate $80 million increase related to mark-to-market impacts associated with DEFS hedges resulting from prior year losses of approximately $105 million offset by 2006 losses of approximately $25 million.

Consolidated Interest Expense

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated interest expense for the three months ended September 30, 2006 increased $109 million, compared to the same period in 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated interest expense for the nine months ended September 30, 2006 increased $112 million, compared to the same period in 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy, partially offset by reduced interest expense associated with DEFS, which was deconsolidated on July 1, 2005.

Consolidated Minority Interest Expense

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated minority interest expense for the nine months ended September 30, 2006 decreased $458 million, compared to the same period in 2005. The decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the impact of deconsolidation of DEFS.

PART I

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated income tax expense from continuing operations for the three months ended September 30, 2006 decreased $65 million, compared to the same period in 2005. The decrease primarily resulted from lower pre-tax earnings. The effective tax rate increased in the three months ended September 30, 2006 (37.1%) compared to the same period in 2005 (34.5%), due primarily to an increase in state taxes as a result of setting up an additional tax reserve attributed to the sale of the interest in Crescent.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated income tax expense from continuing operations for the nine months ended September 30, 2006 decreased $240 million, compared to the same period in 2005. This decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above, offset by the 2006 gain on Crescent. The effective tax rate increased in the nine months ended September 30, 2006 (34.3%) compared to the same period in 2005 (34.1%), due primarily to the increase in state taxes as a result of setting up an additional tax reserve attributed to the sale of the interest in Crescent, offset by a reduction in state deferred tax liabilities related to the merger with Cinergy.

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

Three Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated income (loss) from discontinued operations, net of tax for the three months ended September 30, 2006 improved $929 million, compared to the same period in 2005. This increase primarily resulted from approximately $31 million of after-tax income at DENA during the three months ended September 30, 2006 as a result of certain contract terminations or sales, as compared to an approximate $0.8 billion after-tax charge (approximately $1.3 billion pre-tax) in 2005 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 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). Additionally, Commercial Power recognized approximately $15 million of after-tax income during the three months ended September 30, 2006 associated with exiting the Cinergy commercial marketing and trading operations.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005.Consolidated income (loss) from discontinued operations, net of tax for the nine months ended September 30, 2006 improved $732 million compared to the same period in 2005. This decrease primarily resulted from approximately $164 million of after-tax losses at DENA in 2006 associated with certain contract terminations or sales, as compared to an approximate $0.8 billion, after-tax impairment charge (approximately $1.3 billion pre-tax) in 2005 related to DENA, discussed above.

Segment Results

Management evaluates segment performance 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.

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.

See Note 14 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s new segment structure. Additionally, the results of operations and segment assets for DENA Midwestern operations are included in the Commercial Power segment, whereby previously DENA’s Midwestern operations were included in Other.

PART I

EBIT by Business Segment


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in millions)
U.S. Franchised Electric and Gas	$	678		$	606		$	1,388		$	1,216
Natural Gas Transmission		303			329			1,102			1,044
Field Services^(a)		158			701			450			1,784
Commercial Power		57			(11	)		50			(44	)
International Energy		68			63			181			217
Crescent^(c)		300			120			515			210

Total reportable segment EBIT		1,564			1,808			3,686			4,427
Other		(111	)		(165	)		(343	)		(452	)

Total reportable segment and other EBIT		1,453			1,643			3,343			3,975
Interest expense		(337	)		(228	)		(925	)		(813	)
Interest income and other^(b)		23			(4	)		75			45

Consolidated earnings from continuing operations before income taxes	$	1,139		$	1,411		$	2,493		$	3,207

(a)

In July 2005, Duke Energy completed the 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 foreign currency transaction gains and losses, additional minority interest expense not allocated to the segment results.

(c)

In September 2006, Duke Energy completed a joint venture transaction of Crescent (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). As a result, Crescent EBIT for the three and nine months ended September 30, 2006 includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.

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

U.S. Franchised Electric and Gas


	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,482		$	1,619	$	863		$	5,904	$	4,118	$	1,786
Operating expenses		1,814			1,026		788			4,543		2,916		1,627
Gains on sales of other assets and other, net		(1	)		1		(2	)		1		2		(1	)

Operating income		667			594		73			1,362		1,204		158
Other income and expenses, net		11			12		(1	)		26		12		14

EBIT	$	678		$	606	$	72		$	1,388	$	1,216	$	172

Duke Energy Carolinas GWh sales^(a)		22,755			23,724		(969	)		63,279		65,318		(2,039	)
Duke Energy Midwest GWh sales^(a)(b)		16,505					16,505			31,309				31,309

(a)	Gigawatt-hours (GWh)

(b)	Relates to operations of former Cinergy

PART I

The following table shows the changes in GWh sales and average number of customers for Duke Energy Carolinas. The table below excludes amounts related to former Cinergy since results of operations of Cinergy are only included from the date of acquisition and thereafter.


Increase (decrease) over prior year	Three Months Ended		Nine Months Ended
Residential sales^a	1.8	%	0.3	%
General service sales^a	2.9	%	2.0	%
Industrial sales^a	(4.1	)%	(2.8	)%
Wholesale sales	(73.8	)%	(43.3	)%
Total DE Carolinas sales^b	(4.1	)%	(3.1	)%
Average number of customers	2.1	%	2.0	%

^a	Major components of DE Carolinas’ retail sales

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

Three Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was driven primarily by:

•

An $881 million increase in regulated revenues due to the acquisition of Cinergy

•

A $67 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs and increased GWh sales to retail customers. Sales to residential and commercial customers increased by approximately 2%, resulting in more fuel revenue collections from those customers. The delivered cost of coal in 2006 is approximately $15 per ton higher than the same period in 2005, representing a 27% increase

•

A $16 million increase related to the sharing of profits from wholesale power sales with industrial customers in North Carolina in 2006. For the three months ended September 30, 2006, the sharing of profits was less than $1 million, while for the same period in 2005 the sharing of profits was $16 million, partially offset by

•

A $61 million decrease in wholesale power revenues. Sales volumes decreased by 74% due to production constraints caused by generation outages and mild weather. Additionally, 2006 pricing was lower compared to 2005 due to the impact of hurricanes in 2005

•

A $39 million decrease related to the sharing of anticipated merger savings by way of a rate decrement rider with regulated customers in North Carolina and South Carolina. As a requirement of the merger, Duke Energy Carolinas is required to share anticipated merger savings of approximately $117 million with North Carolina customers and approximately $40 million with South Carolina customers over a one year period, and

•

A $17 million decrease related to GWh sales to retail customers due to unfavorable weather conditions compared to the same period in 2005. Weather statistics for cooling degree days were approximately 3% above normal in third quarter 2006 compared to 19% above normal during the same period in 2005.

Operating Expenses.The increase was driven primarily by:

•

A $707 million increase in regulated operating expenses due to the acquisition of Cinergy

•

A $60 million increase in fuel expenses due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation during the third quarter of 2006 and 2005 and the delivered cost of coal is approximately $15 per ton higher than the same period in 2005

•

A $24 million increase in purchased power expense, due primarily to less generation availability during third quarter of 2006 as a result of outages at base load stations

•

A $20 million increase in operating and maintenance expenses, primarily related to higher nuclear costs, increases in insurance premiums, environmental charges and workers’ compensation costs, partially offset by

•

A $23 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during the third quarter of 2006 as compared to the same period in 2005. Regulatory amortization expenses were approximately $62 million for the three months ended September 30, 2006 as compared to approximately $85 million during the same period in 2005.

PART I

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy and less regulatory amortization, partially offset by decreased sales to wholesale customers due to limited market opportunities, sharing of anticipated merger savings, increased purchased power costs, higher operating and maintenance expenses and less favorable weather conditions.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was driven primarily by:

•

A $1,729 million increase in regulated revenues due to the acquisition of Cinergy

•

A $144 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs. The delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005, representing a 19% increase

•

A $19 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in the DE Carolinas’ service territory. The number of customers in 2006 has increased by approximately 44,000 compared to the same period in 2005, partially offset by

•

A $76 million decrease in wholesale power revenues. Sales volumes decreased by 43% due to production constraints caused by generation outages and milder weather. Additionally, 2006 pricing was unfavorable compared to 2005 due to the impact of hurricanes in 2005

•

A $42 million decrease related to the sharing of anticipated merger savings by way of a rate decrement rider with regulated customers in North Carolina and South Carolina. As a requirement of the merger, Duke Energy Carolinas is required to share anticipated merger savings of approximately $117 million with North Carolina customers and approximately $40 million with South Carolina customers over a one year period, and

•

A $12 million decrease related to GWh sales to retail customers due to unfavorable weather conditions compared to the same period in 2005. Weather statistics for both heating and cooling periods in 2006 were unfavorable compared to the same periods in 2005.

Operating Expenses.The increase was driven primarily by:

•

A $1,470 million increase in regulated operating expenses due to the acquisition of Cinergy

•

A $140 million increase in fuel expenses, due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation for year to date September 30, 2006 and 2005 and the delivered cost of coal is approximately $11 per ton higher than the same period in 2005

•

A $36 million increase in operating and maintenance expenses, primarily related to base load station maintenance costs, increases in insurance premiums, environmental charges and workers’ compensation costs

•

A $20 million increase in purchased power expense, due primarily to less generation availability during 2006 as a result of outages at base load stations, partially offset by

•

A $53 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005. Regulatory amortization expenses were approximately $188 million for the nine months ending September 30, 2006 as compared to approximately $241 million during the same period in 2005.

Other Income and Expenses, net.The increase in other income was driven primarily by the acquisition of Cinergy.

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, increased demand from retail customers and less regulatory amortization, partially offset by lower wholesale power sales, sharing of anticipated merger savings and increased operating and maintenance costs.

PART I

Natural Gas Transmission


	Three Months Ended September 30,							Nine Months Ended September 30,
	2006		2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	871	$	869	$	2		$	3,324	$	2,824	$	500
Operating expenses		586		549		37			2,276		1,809		467
Gains on sales of other assets and other, net		2		—		2			31		4		27

Operating income		287		320		(33	)		1,079		1,019		60
Other income and expenses, net		25		17		8			52		48		4
Minority interest expense		9		8		1			29		23		6

EBIT	$	303	$	329	$	(26	)	$	1,102	$	1,044	$	58

Proportional throughput, TBtu^a		729		759		(30	)		2,398		2,534		(136	)

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, 2006 as Compared to September 30, 2005

Operating Revenues.The slight increase was driven primarily by:

•

A $32 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 $31 million increase due primarily to higher processing revenues on the Empress System, as a result of increased commodity prices

•

A $7 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses, and

•

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

•

A $47 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage, and

•

A $12 million decrease in US business operations driven by lower processing revenues and a 2005 insurance recovery.

Operating Expenses.The increase was driven primarily by:

•

A $35 million increase in the U.S. primarily related to higher insurance premiums, benefits costs, pipeline integrity costs, and other increased transmission and storage operation expenses,

•

A $25 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above),

•

A $7 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

•

A $4 million increase at British Columbia Pipeline System for higher plant maintenance turnaround costs, and

•

A $3 million increase due primarily to higher gas purchase cost associated with the Empress System, partially offset by

•

A $46 million decrease in gas purchase costs at Union Gas, primarily resulting from lower gas usage.

Other Income and Expenses, net.The increase was driven primarily by a pre-tax SAB No. 51 gain of $15 million related to a dilution gain on the Income Fund’s issuance of additional units of the Canadian income trust fund, partially offset by a $3 million decrease in Gulfstream equity due to lower earnings from increased interest expense.

EBIT. The decrease in EBIT is due primarily to the increase in U.S. operating and maintenance expenses, a decrease in U.S business operations, and a 2005 insurance recovery, partially offset by increased processing earnings (Empress System), the gain on the Income Fund’s issuance of additional units of the Canadian income trust fund, and the strengthening Canadian currency.

PART I

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was driven primarily by:

•

A $298 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices

•

A $152 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses.

•

A $134 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 $29 million increase in U.S. business operations driven by increased processing revenues associated with transportation, partially offset by a 2005 insurance recovery, and

•

A $21 million increase from completed and operational pipeline expansion projects in the U.S., partially offset by

•

A $150 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to warmer weather compared to 2005.

Operating Expenses.The increase was driven primarily by:

•

A $225 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System

•

A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

•

A $106 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above) and

•

A $66 million increase in U.S. primarily related to higher insurance premiums, benefits costs, IT costs, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

•

A $127 million decrease in gas purchase costs at Union Gas, primarily resulting from lower gas usage due to unseasonably warmer weather and

•

A $15 million decrease related to the resolution in 2006 of prior tax years’ ad valorem tax issues.

Gain on Sales of Other Assets and Other, net.The increase was driven primarily by a $23 million gain in 2006 on the settlement of a customer’s transportation contract, and a $5 million gain on the sale of Stone Mountain assets in 2006.

Other Income and Expenses, net.The increase was driven primarily a pre-tax SAB No. 51 gain of $15 million related to the Income Fund’s issuance of additional units of the Canadian income trust fund, partially offset by a $5 million construction fee received in 2005 from an affiliate as a result of the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), 50% owned by Duke Energy, Phase II project, and Natural Gas Transmission’s 50% share of operating and maintenance expenses in 2006 on the Southeast Supply Header project.

EBIT. The increase in EBIT is due primarily to the increase in processing earnings (Empress System), the gain on settlement of a customer’s transportation contract, U.S. business expansion and operations, the gain on the Income Fund’s issuance of additional units of the Canadian income trust fund and the strengthening Canadian currency, partially offset by increased U.S. operating and maintenance expenses, the 2005 Gulfstream success fee and unfavorable Union weather and operations.

Matters Impacting Future Results

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. Approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries is anticipated to transfer to the new natural gas company at the time of the spin-off. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

During the quarter ended September 30, 2006, Natural Gas Transmission recognized a $15 million pre-tax gain on the sale of additional units of the Canadian income trust fund, the Duke Energy Income Fund (Income Fund). If the Income Fund issues additional units in the future to finance its cash needs, Natural Gas Transmission could recognize future SAB No. 51 gain or loss transactions.

PART I

On October 31, 2006, the Minister of Finance in Canada announced proposed changes to the income tax treatment of “flow-through entities”, including income trusts, such as the Income Fund. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions which would apply beginning with the 2011 taxation year of the Income Fund. Duke Energy will monitor the impact of these proposed changes on the Income Fund and on the future use of such entities, but does not currently expect significant impacts to Natural Gas Transmission as a result of these changes.

Field Services


	Three Months Ended September 30,									Nine Months Ended September 30,
	2006			2005			Increase (Decrease)			2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—		$	—		$	—		$	—		$	5,530	$	(5,530	)
Operating expenses		1			—			1			4			5,211		(5,207	)
Gains on sales of other assets and other, net		—			576			(576	)		—			577		(577	)

Operating income		(1	)		576			(577	)		(4	)		896		(900	)
Equity in earnings of unconsolidated affiliates^(a)		159			126			33			454			126		328
Other income and expenses, net		—			(1	)		1			—			1,259		(1,259	)
Minority interest expense		—			—			—			—			497		(497	)

EBIT^(a)	$	158		$	701		$	(543	)	$	450		$	1,784	$	(1,334	)

Natural gas gathered and processed/transported, TBtu/d^(b)		6.7			6.7			—			6.8			6.8		—
NGL production, MBbl/d^(c)		361			342			19			361			355		6
Average natural gas price per MMBtu^(d)(e)	$	6.58		$	8.37		$	(1.79	)	$	7.45		$	7.12	$	0.33
Average NGL price per gallon^(e)	$	1.02		$	0.91		$	0.11		$	0.96		$	0.80	$	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. 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. Average price based on NYMEX Henry Hub

(e)	Does not reflect results of commodity hedges.

Three months ended September 30, 2006 as Compared to September 30, 2005

Gains on Sales of Other Assets and Other, net.The decrease was due primarily to an approximate pre-tax gain of $575 million on the DEFS disposition transaction during the prior year.

Equity in Earnings of Unconsolidated Affiliates. The increase is due to Duke Energy’s 50% of equity earnings of DEFS’ net income for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005. DEFS’ earnings during the three months ended September 30, 2006 have continued to be favorably impacted by increased NGL and crude oil prices as compared to the prior period, as well as increased trading and marketing gains due primarily to changes in natural gas prices and the timing of derivative and inventory transactions.

EBIT. The decrease in EBIT resulted mainly from the pre-tax gain of $575 million on the DEFS disposition transaction during the prior year, offset by the increase in equity in earnings for the three months ended September 30, 2006 as compared to the prior year.

Nine months ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Operating expenses for the nine months ended September 30, 2005 were also impacted by approximately $120 million of losses recognized due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges.

PART I

Gains on Sales of Other Assets and Other, net.The decrease was due primarily to an approximate pre-tax gain of $575 million on the DEFS disposition transaction during the prior year.

Equity in Earnings of Unconsolidated Affiliates.The increase is due to Duke Energy’s 50% of equity in earnings of DEFS’ net income for the nine months ended September 30, 2006 as compared to equity in earnings of DEFS’ net income for the three months ended September 30, 2005. DEFS’ earnings during the nine months ended September 30, 2006 have continued to be favorably impacted by increased NGL and crude oil prices as compared to the prior period, as well as increased trading and marketing gains due primarily to changes in natural gas prices and the timing of derivative and inventory transactions. These increases have been partially offset by higher operating costs and expenses for repair and maintenance for the nine months ended September 30, 2006.

Other Income and Expenses, net. The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. During the nine months ended September 30, 2005, DEFS had a pre-tax gain on the sale of its wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP of $1.1 billion, and Duke Energy had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.

Minority Interest Expense.The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Minority interest expense for the nine months ended September 30, 2005 was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion, as discussed above.

EBIT. The decrease in EBIT resulted primarily from the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP during the nine months ended September 30, 2005 and gain on the the DEFS disposition transaction, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50%. These decreases were partially offset by increased commodity prices for the nine months ended September 30, 2006 as compared to the prior period.

Supplemental Data

Below is supplemental information for DEFS operating results for the three and nine months ended September 30, 2006 and the three months ended September 30, 2005:


(in millions)	Three Months Ended September 30, 2006		Three Months Ended September 30, 2005			Nine Months Ended September 30, 2006
Operating revenues	$	3,190	$	3,386		$	9,501
Operating expenses		2,841		3,105			8,492

Operating income		349		281			1,009
Other income and expenses, net		—		2			10
Interest expense, net		29		33			89
Income tax expense (benefit)		2		(2	)		22

Net income	$	318	$	252		$	908

Matters Impacting Future Results

As previously mentioned, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

In July 2006, the State of New Mexico Environment Department issued Compliance Order to DEFS that list air quality violations during the past five year at three DEFS owned or operated facilities in New Mexico. DEFS intends to contest these allegations. Management of DEFS does not believe this matter will result in a material impact on DEFS’ future consolidated results of operations, cash flows or financial position.

PART I

Commercial Power


	Three Months Ended September 30,									Nine Months Ended September 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	497		$	78		$	419		$	960		$	127		$	833
Operating expenses		452			89			363			928			172			756
Gains on sales of other assets and other, net		(4	)		—			(4	)		(9	)		—			(9	)

Operating income		41			(11	)		52			23			(45	)		68
Other income and expenses, net		16			—			16			27			1			26

EBIT	$	57		$	(11	)	$	68		$	50		$	(44	)	$	94

Actual Plant Production, Gwh		6,599			958			5,641			11,978			1,664			10,314

Three Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was primarily driven by the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected for the three months ended September 30, 2006, but are not included in the same period in 2005. Operating revenues associated with the DENA Midwest plants were approximately $50 million lower for the three months ended September 30, 2006 compared to the same period in the prior year primarily due to lower plant production and unfavorable hedge results.

Operating Expenses.The increase was primarily driven by the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected for the three months ended September 30, 2006, but are not included in the same period in 2005. Operating expenses associated with the DENA Midwest plants were approximately $65 million lower for the three months ended September 30, 2006 compared to the same period in the prior year primarily due to lower plant production and improved fuel hedge results.

Gain on Sales of Other Assets and Other, net.The decrease was driven primarily by losses of approximately $9 million on sales of emission allowances, offset by an approximate $6 million gain on the sale of the Pine Mountain synthetic fuel facility.

EBIT.The increase was due primarily to the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected for the three months ended 2006, but are not included in 2005. Results for the three months ended September 30, 2005 relate to the DENA Midwest assets. EBIT losses for these assets decreased approximately $15 million for the three months ended September 30, 2006 as compared to the same period in the previous year.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was primarily driven by the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Operating revenues associated with the DENA Midwest plants were approximately $91 million lower for the nine months ended September 30, 2006 compared to the same period in the prior year primarily due to lower plant production and unfavorable hedge results.

Operating Expenses.The increase was primarily driven by the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Operating expenses associated with the DENA Midwest plants were approximately $101 million lower for the nine months ended September 30, 2006 compared to the same period in the prior year primarily due to lower plant production and improved fuel hedge results.

Gain on Sales of Other Assets and Other, net.The decrease was driven primarily by losses of approximately $15 million on sales of emission allowances, offset by an approximate $6 million gain on the sale of the Pine Mountain synthetic fuel facility.

EBIT.The increase was due primarily to the acquisition of Cinergy assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Results for the nine months ended 2005 relate to the DENA Midwest assets. EBIT losses for these assets decreased approximately $10 million in 2006 compared to the same period in the prior year.

PART I

International Energy


	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005		Increase (Decrease)			2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	238		$	186	$	52		$	719		$	536	$	183
Operating expenses		187			139		48			577			385		192
Gains on sales of other assets and other, net		(1	)		1		(2	)		(1	)		1		(2	)

Operating income		50			48		2			141			152		(11	)
Other income and expenses, net		25			19		6			56			74		(18	)
Minority interest expense		7			4		3			16			9		7

EBIT	$	68		$	63		5		$	181		$	217	$	(36	)

Sales, GWh		5,485			4,493		992			15,715			13,555		2,160
Proportional megawatt capacity in operation										3,995			4,064		(69	)

Three Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was driven primarily by:

•

A $41 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”), and increased thermal generation in Egenor, and

•

A $7 million increase in Argentina primarily due to higher electricity generation due to favorable hydrology, higher electricity prices and increased gas marketing sales.

Operating Expenses.The increase was driven primarily by:

•

A $39 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”), and increased purchased power and fuel costs in Egenor, and

•

A $10 million increase in Brazil due to unfavorable exchange rates, increased regulatory fees, and increased purchased power.

Other Income and Expenses, net. The increase was driven primarily by a $20 million equity investment impairment recorded in the prior year related to Campeche, offset by an $8 million decrease in equity earnings in 2006 from NMC due to lower MTBE margins and an unplanned outage.

EBIT. The increase in EBIT was primarily due to the prior year impairment as discussed above, offset by higher purchased power costs in Egenor, and lower MTBE margins and an unplanned outage at NMC in 2006.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues.The increase was driven primarily by:

•

A $89 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and an increase in energy sales in Egenor.

•

A $41 million increase in El Salvador primarily due to higher energy prices as a result of a favorable regulatory price bid methodology.

•

A $28 million increase in Brazil due to favorable exchange rates and higher average energy prices, offset by lower volumes, and

•

A $25 million increase in Argentina mainly due to higher electricity generation as a result of favorable hydrology, higher electricity prices and increased gas marketing sales.

Operating Expenses.The increase was driven primarily by:

•

A $88 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and increased purchased power and fuel costs in Egenor

•

A $36 million increase in El Salvador primarily due to higher fuel prices and increased fuel consumption

•

A $32 million increase in Mexico mainly due to an allowance on notes receivable from the Campeche equity investment, and

•

A $30 million increase in Brazil due to unfavorable exchange rates, increased regulatory fees, and purchased power costs

PART I

Other Income and Expenses, net. The decrease was primarily due to the increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”), in addition to lower MTBE margins and unplanned outages at NMC.

EBIT. The decrease in EBIT was primarily due to an impairment of the Campeche equity investment and notes receivable as discussed above and higher purchased power costs in Egenor due to lower hydrology, offset by favorable hydrology and pricing in Argentina.

Matters Impacting Future Results

The Bolivian government has announced plans to nationalize its energy infrastructure. As a result, management is currently monitoring the potential impact on its 50 percent interest in Corani. Depending upon future actions of the Bolivian government, Duke Energy’s investment in Corani could become impaired. Additionally, Duke Energy is evaluating various options related to certain of its operations, principally in Bolivia and Ecuador, which could include the sale or other disposition of these operations. Impairments or losses could be recognized in future periods if Duke Energy decides to pursue such a sale or disposition of any of these operations.

Crescent (a)


	Three Months Ended September 30,									Nine Months Ended September 30,
	2006			2005			Increase (Decrease)			2006			2005		Increase (Decrease)
	(in millions)
Operating revenues	$	66		$	105		$	(39	)	$	221		$	281	$	(60	)
Operating expenses		37			95			(58	)		158			225		(67	)
Gains on sales of investments in commercial and multi-family real estate		30			63			(33	)		201			117		84
Gains on sales of other assets and other, net		246			—			246			246			—		246

Operating income		305			73			232			510			173		337
Equity in earnings of unconsolidated affiliates		(4	)		—			(4	)		(4	)		—		(4	)
Other income and expenses, net		1			46			(45	)		14			44		(30	)
Minority interest expense		2			(1	)		3			5			7		(2	)

EBIT	$	300		$	120		$	180		$	515		$	210	$	305

(a)	In September 2006, Duke Energy completed a joint venture transaction at Crescent. As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity investment for the periods subsequent to September 7, 2006.

Three Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by a $31 million decrease in residential developed lot sales, primarily due to decreased sales at the LandMar division in Florida.

Operating Expenses.The decrease was driven primarily by a $23 million decrease in the cost of residential developed lot sales as noted above and a $16 million impairment charge in the third quarter 2005 related to a residential community in South Carolina (Oldfield).

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by a $41 million land sale gain at Catawba Ridge in South Carolina in the third quarter of 2005 compared to lesser activity in the third quarter of 2006.

Gains on Sales of Other Assets and Other, net. The increase was due to an approximate $250 million pre-tax gain on Duke Energy’s sale of 50% of its interest in Crescent (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Other Income and expenses, net. The decrease is primarily due to the $45 million gain from the sale of assets owned by Crescent Brookdale Associates, an unconsolidated joint venture, in the third quarter of 2005 with no comparable gains in the third quarter of 2006.

EBIT.The increase is due primarily to an approximate $250 million gain on the sale of ownership interests in Crescent in the third quarter 2006, as discussed above, partially offset by the gains on the sale of Catawba Ridge and Brookdale in the third quarter of 2005 as noted above.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by a $51 million decrease in residential developed lot sales, primarily due to decreased sales at the LandMar division in Florida.

PART I

Operating Expenses.The decrease was driven primarily by a $41 million decrease in the cost of residential developed lot sales as noted above and a $16 million impairment charge in 2005 related to a residential community in South Carolina (Oldfield).

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by an $81 million gain on the sale of two office buildings at Potomac Yard in Washington, DC along with a $52 million land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale at Catawba Ridge in South Carolina in 2005.

Other Income and Expenses, net. The decrease is primarily due to the $45 million gain from the sale of assets owned by Crescent Brookdale Associates, an unconsolidated joint venture, in the third quarter of 2005 with no comparable gains during the nine months ended September 30, 2006.

EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the sale of an ownership interest in Crescent as noted above.

Matters Impacting Future Results

In September 2006, Duke Energy closed an agreement to create a joint venture of Crescent and sold an effective 50% interest in Crescent to the MS Members. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which $1.19 billion was immediately distributed to Duke Energy. Subsequent to the sale, Duke Energy deconsolidated its investment in the Crescent JV and has accounted for the investment under the equity method of accounting. The combination of Duke Energy’s reduction in ownership and the increased interest expense at Crescent JV as a result of the debt transaction, the impacts of which will be reflected in Duke Energy’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Energy will recognize in future periods. Since the Crescent JV will capitalize interest as a component of project costs, the impacts of the interest expense on Duke Energy’s equity earnings will be recognized as projects are sold by the Crescent JV.

Other


	Three Months Ended September 30,									Nine Months Ended September 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	67		$	225		$	(158	)	$	338		$	430		$	(92	)
Operating expenses		211			293			(82	)		679			796			(117	)
Gains on sales of other assets and other, net		3			3			—			—			7			(7	)

Operating income		(141	)		(65	)		(76	)		(341	)		(359	)		18
Other income and expenses, net		32			(103	)		135			(7	)		(100	)		93
Minority interest expense		2			(3	)		5			(5	)		(7	)		2

EBIT	$	(111	)	$	(165	)	$	54		$	(343	)	$	(452	)	$	109

Three Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by:

•

A $130 million decrease due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD

•

A $30 million decrease due to a prior year mark-to-market gain related to DENA’s hedge discontinuance in the Southeast.

Operating Expenses. The decrease was driven primarily by:

•

A $143 million decrease due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD

•

A $46 million decrease due primarily to the recognition of reserves for estimated property damage related to hurricanes and business interruption losses in 2005, and timing of other captive insurance claims, partially offset by

•

A $55 million increase in charges for liabilities associated with mutual insurance companies

•

A $23 million increase in corporate governance and other costs due primarily to the merger with Cinergy in April 2006

PART I

•

A $19 million increase due to costs-to-achieve in 2006 related to the Cinergy merger

•

A $10 million increase due to costs-to-achieve in 2006 related to the anticipated spin-off of Duke Energy’s natural gas business.

Other Income and Expenses, net. The increase was driven primarily by an approximate $125 million favorable variance resulting from the realized and unrealized mark-to-market impacts associated with certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

EBIT.The increase was due primarily to the favorable variance related to realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk. This increase was partially offset by decreases due to charges in 2006 associated with Cinergy merger and natural gas business spin-off costs-to-achieve, and an increase in corporate governance and other costs due to the merger with Cinergy.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by:

•

A $203 million decrease due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD

•

A $30 million decrease due to a prior year mark-to-market gain related to DENA’s hedge discontinuance in the Southeast, partially offset by

•

An approximate $130 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DEFS, effective July 1, 2005.

Operating Expenses. The decrease was driven primarily by:

•

A $249 million decrease due to the continued wind-downs of DETM, DEM and Duke Energy’s 50% interest in D/FD

•

A $38 million decrease due primarily to the recognition of reserves for estimated property damage related to hurricanes and business interruption losses in 2005, and timing of other captive insurance claims, partially offset by

•

A $13 million increase in charges for liabilities associated with mutual insurance companies

•

A $43 million increase in corporate governance and other costs due primarily to the merger with Cinergy in April 2006

•

A $97 million increase due to costs-to-achieve in 2006 related to the Cinergy merger

•

A $17 million increase due to costs-to-achieve in 2006 related to the anticipated spin-off of Duke Energy’s natural gas business.

Other Income and Expenses, net. The increase was driven primarily by an approximate $80 million favorable variance resulting from the realized and unrealized mark-to-market impacts associated with certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

EBIT.The increase was due primarily to the favorable variance related to realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, and favorable captive insurance results. These increases were partially offset by decreases due to charges in 2006 associated with Cinergy merger and natural gas business spin-off costs-to-achieve, and an increase in corporate governance and other costs due to the merger with Cinergy.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities increased $236 million for the nine months ended September 30, 2006 compared to the same period in 2005. This change was driven primarily by:

•

The impacts of the merger with Cinergy, effective April 3, 2006,

•

Collateral received by Duke Energy (approximately $540 million) in 2006 from Barclays, partially offset by

•

The settlement of the payable to Barclays (approximately $600 million) in 2006, and

•

An approximate $400 million decrease in 2006 due to the net settlement of remaining DENA contracts.

PART I

Investing Cash Flows

Net cash used in investing activities increased $1,380 million for the nine months ended September 30, 2006 compared to the same period in 2005. This change was driven primarily by:

•

An approximate $950 million increase in short-term investments in 2006 as compared to 2005, due primarily to proceeds from the Crescent debt financing, and

•

An approximate $480 million increase in 2006 capital and investment expenditures, primarily related to Cinergy.

Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $1,634 million for the nine months ended September 30, 2006, compared to the same period in 2005. This change was driven primarily by:

•

An approximate $1.4 billion increase in the proceeds from the issuance of long-term debt in 2006, net of redemptions, due to the Crescent JV transaction

•

An approximate $400 million decrease in share repurchases under the accelerated share repurchase plan due to the repurchase of 32.6 million shares of common stock for approximately $933 million during the nine months ended September 30, 2005, compared to the repurchase of 17.5 million shares for approximately $500 million during the nine months ended September 30, 2006, partially offset by

•

An approximate $271 million increase in dividends paid due to the increase in the quarterly dividend paid per share combined with a larger number of shares outstanding primarily due to the merger with Cinergy.

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, in connection with the announcement of the merger with Cinergy, Duke Energy suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy had repurchased approximately $933 million of common stock. In the first quarter of 2006, as a result of the March 10, 2006 shareholder approval of the merger, Duke Energy’s Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. During the nine months ended September 30, 2006, Duke Energy repurchased approximately 17.5 million shares for total consideration of approximately $500 million. The repurchases and corresponding commissions and other fees were recorded in Common Stockholder’s Equity as a reduction in common stock and additional paid-in capital. In June 2006, Duke Energy suspended additional repurchases of Duke Energy common stock under the repurchase plan due to its plan to spin off the natural gas businesses. At the time of the June 2006 suspension of the repurchase plan, Duke Energy had repurchased approximately 50 million shares of common stock for approximately $1.4 billion since inception of the repurchase plan. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed.

Significant Financing Activities. During the nine months ended September 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $763 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $460 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the DENA business.

In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio, Inc. (Duke Energy Ohio). Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

In September 2006, prior to the completion of the partial sale of Crescent to the MS Members as discussed in Note 2, Crescent issued approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were distributed by Crescent to Duke Energy and recorded as a Financing Activity on the Consolidated Statements of Cash Flows. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’s Consolidated Balance Sheets.

During the three months ended September 30, 2006, Duke Energy increased the portion of outstanding commercial paper and pollution control bond balances classified as long-term from $300 million to $779 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

PART I

In September 2006, Union Gas entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%.

During October 2006, the $130 million bi-lateral credit facility at Duke Capital was cancelled. In addition, the remaining $120 million bi-lateral credit facility was cancelled in November 2006 and reissued at Duke Energy for the same amount with the same terms and conditions.

During 2006, Duke Energy has repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders (see “Other Issues”), the share repurchase program has since been suspended.

During the second and third quarters of 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold during each respective quarter. Holders of the convertible debt were able to exercise their right to convert on or prior to each quarter end. During the second and third quarters, approximately $632 million of debt was converted into approximately 27 million shares of Duke Energy Common Stock. At September 30, 2006, the balance of the convertible debt is approximately $110 million and remains convertible in the fourth quarter of 2006 into approximately 4.7 million shares of Duke Energy common stock as a result of the stock having achieved a specified price threshold during the third quarter.

In October 2006, Duke Energy received pre-tax proceeds of approximately $700 million from the sale of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (collectively CMT) to Fortis.

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

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

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

In August 2005, Duke Energy’s International 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 and 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%.

Duke Energy’s U.S. Franchised Electric & Gas business is evaluating the construction of several large, new electric generating plants in North Carolina, South Carolina, and Indiana. During this evaluation process, Duke Energy has begun to see significant increases in the estimated costs of these projects driven by strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. As a result of such increases, Duke Energy recently made a filing with the North Carolina Utilities Commission related to the Duke Energy Carolinas request for a Certificate of Public Convenience and Necessity (CPCN) to build two 800-megawatt coal units at its existing Cliffside Steam Station. In this filing, Duke Energy Carolinas states the rising costs described above could increase the cost of building the Cliffside units from approximately $2 billion to approximately $3 billion. Duke Energy made this updated filing so that the Commission would have the most current cost information prior to issuing a CPCN in this proceeding.

Duke Energy Indiana’s estimated costs associated with the potential construction of an Integrated Gasification and Combined Cycle plant in Indiana have also increased. Duke Energy Indiana’s publicly filed testimony with the Indiana Utility Regulatory Commission indicates that industry (EPRI) total capital requirement estimates for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owner’s specific site costs).

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Effective with the third quarter 2006, the Board of Directors of Duke Energy have approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

Available Credit Facilities and Restrictive Debt Covenants.Duke Energy’s debt and 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, 2006, 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 debt or credit agreements contain material adverse change clauses.

Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P), Moody’s Investors Service (Moody’s) and Dominion Bond Rating Service (DBRS).

The most recent rating action by S&P occurred in September 2006 when S&P changed the outlook of Duke Capital, Texas Eastern Transmission, LP, Union Gas and Westcoast Energy Inc. (collectively the gas entities) from developing to positive following the completion of their assessment of Duke Energy’s announcement of the separation of the electric and gas businesses. S&P had earlier in June 2006 changed the outlook of the gas entities from positive to developing due to S&P’s uncertainty as to how the new gas company would be capitalized and funded. In May 2006, S&P changed the outlook of Duke Energy and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and Duke Energy Trading and Marketing, LLC from stable to positive reflecting Duke Energy’s announcement to sell Cinergy’s commercial trading and marketing operations. In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P lowered the credit rating of Cinergy Corp. and raised the credit rating of Duke Capital each one ratings level as disclosed in the table below. At the same time, S&P removed Cinergy and its subsidiaries from credit-watch negative, assigned a credit rating to Duke Energy Carolinas, LLC (formerly Duke Power Company LLC) and left the remaining credit ratings in the table disclosed below unchanged. At the completion of S&P’s April action, all the credit ratings were on stable outlook. S&P’s ratings action in April also included a lowering of Cinergy’s Corporate Credit Rating (CCR) consistent with Duke Energy’s CCR as disclosed in the table below. S&P last affirmed its rating for M&N Pipeline in July 2006 where it has remained unchanged with a stable outlook for the last several years.

The most recent rating action by Moody’s occurred in October 2006 when the credit ratings of Duke Capital and Texas Eastern Transmission, LP were placed under review for possible upgrade following Moody’s preliminary assessment of Duke Capital’s pending restructuring as a subsidiary of the new natural gas company, which would be named Spectra Energy. In April 2006 upon Duke Energy’s completion of the merger with Cinergy, Moody’s upgraded the credit ratings of Duke Energy Carolinas, LLC (formerly rated as Duke Energy by Moody’s prior to the merger), Duke Capital and Texas Eastern Transmission, LP one ratings level each and assigned an issuer rating to New Duke Energy as disclosed in the table below. Moody’s concluded their April action placing New Duke Energy and Duke Energy Carolinas, LLC on positive outlook and Duke Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s also confirmed all of Cinergy and its subsidiaries credit ratings and changed the outlook to positive with the exception of Duke Energy Indiana, Inc. (formerly PSI Energy, Inc.) which was left on stable outlook. Moody’s noted in their April action the substantial reduction in business and operating risk of Duke Energy Carolinas, LLC from the distribution of its ownership in Duke Capital to a new holding company and the substantial reduction in business and operating risk of Duke Capital through the restructuring of its ownership in DEFS and the divestiture of the Duke Energy North America merchant generation assets and trading book. Moody’s also noted the upgrade at Texas Eastern Transmission, LP in connection to its parent Duke Capital. In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to the respective ratings disclosed in the table below concluding this action with a stable outlook. Moody’s action was primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. In August 2006, Moody’s revised the outlook for Maritimes & Northeast Pipeline, LLC to negative, noting the potential for a somewhat weaker shipper profile resulting from a recently announced expansion project on the U.S. portion of the pipeline.

The most recent rating action by DBRS occurred in June 2006 when DBRS confirmed the stable trend of the entities disclosed in the table below following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to the entities below has remained unchanged for the last several years with a stable trend.

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The following table summarizes the November 1, 2006 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of November 1, 2006


	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy^(a)	BBB	Baa2	Not applicable
Duke Energy Carolinas, LLC^(b)	BBB	A3	Not applicable
Duke Capital LLC^(b)	BBB	Baa2	Not applicable
Cinergy^(b)	BBB-	Baa2	Not applicable
Duke Energy Ohio, Inc.^(b)	BBB	Baa1	Not applicable
Duke Energy Indiana, Inc.^(b)	BBB	Baa1	Not applicable
Duke Energy Kentucky, Inc.^(b)	BBB	Baa1	Not applicable
Texas Eastern Transmission, LP^(b)	BBB	Baa1	Not applicable
Westcoast Energy Inc.^(b)	BBB	Not applicable	A(low)
Union Gas^(b)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC^(c)	A	A2	A
Maritimes & Northeast Pipeline, LP^(c)	A	A2	A
Duke Energy Trading and Marketing, LLC^(d)	BBB-	Not applicable	Not applicable

(a)	Represents corporate credit rating and issuer rating for S&P and Moody’s respectively

(b)	Represents senior unsecured credit rating

(c)	Represents senior secured credit rating

(d)	Represents corporate credit rating

These entities credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while maintaining the strength of their current balance sheets. In addition, the M&N Pipeline ratings are dependent upon, among other factors, the future gas supply availability and potential changes in customer credit profiles. These credit ratings could be negatively impacted if as a result of market conditions or other factors, these entities are unable to maintain their current balance sheet strength, or if earnings and cash flow outlook materially deteriorates, or if the gas supply availability contracted on the M&N pipeline materially deteriorates, or the M&N customer credit profiles materially deteriorates.

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. On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays acquired substantially all of DENA’s outstanding gas and power derivatives contracts which essentially eliminated Duke Energy’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing. Substantially all of the underlying contracts have been transferred to Barclays.

Duke Energy operates a commercial marketing and trading business that was acquired as part of the merger with Cinergy in April 2006. In June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as associated contracts. The sale closed in October 2006 and, upon closing, the buyer assumed the credit, collateral, market and legal risk associated with the trading positions acquired.

A reduction in the credit rating of Cinergy Corp to below investment grade as of September 30, 2006 would have required the posting of additional collateral of up to approximately $285 million, of which $79 million is related to Duke Energy Ohio, a wholly-owned subsidiary of Cinergy Corp.

A reduction in the credit rating of Duke Capital to below investment grade as of September 30, 2006 would have resulted in Duke Capital posting additional collateral of up to approximately $358 million. The majority of this collateral is related to outstanding surety bonds.

Duke Energy would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Additionally, 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 fully quantify, in addition to the posting of additional collateral and segregation of cash described above.

Other Financing Matters.As of September 30, 2006, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,467 million in gross proceeds from debt and other securities, which include approximately $925 million of effective registrations at legacy Cinergy. Additionally, as of September 30, 2006, Duke Energy had 935 million Canadian dollars (approximately U.S. $838 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 935 million Canadian dollars available under Canadian shelf registrations, 500 million expires in May 2008 and 435 million expires in August 2008.

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Off-Balance Sheet Arrangements

During the nine months ended September 30, 2006, there were changes to Duke Energy’s off-balance sheet arrangements, primarily related to the merger with Cinergy. Cinergy has an agreement to sell certain of their accounts receivable and related collections to Cinergy Receivables, which is a qualified special purpose entity pursuant to SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” (SFAS No. 140) and therefore is an unconsolidated entity of Duke Energy. For further information on Cinergy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Cinergy’s Annual Report on Form 10-K for the year-ended December 31, 2005. For 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, 2005.

Contractual Obligations

Duke Energy enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the nine months ended September 30, 2006, there were material changes in Duke Energy’s contractual obligations from the amounts reported in Duke Energy’s Annual Report on Form 10-K for the year-ended December 31, 2005. These changes primarily relate to approximately $7 billion of contractual obligations assumed as part of the merger with Cinergy, which are primarily comprised of payments on long-term debt, payments under operating and capital leases and contracts to purchase fuel, primarily coal. For an in-depth discussion of Duke Energy’s contractual obligations, see “Contractual Obligations” 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, 2005. Additionally, for information related to Cinergy, see “Contractual Cash Obligations” in “Management’s Discussion and Analysis—Liquidity and Capital Resources” in Cinergy’s Annual Report of Form 10-K for the year ended December 31, 2005.

OTHER ISSUES

Plan to Separate Duke Energy’s Natural Gas and Electric Power Businesses. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and Duke Energy’s 50-percent ownership interest in DEFS. The primary businesses remaining in Duke Energy post-spin are anticipated to principally be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was received during the third quarter of 2006. In addition, approval from the Federal Communications Commission is required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

(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 have been issued, but have not yet been adopted by Duke Energy as of September 30, 2006:

Statement of Financial Accounting Standards (SFAS) No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155).In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, which amends SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”and SFAS No. 140. SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to

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the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (SFAS No. 156).In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.”SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157).In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change Duke Energy’s current practice for measuring and disclosing fair values under other accounting pro

nouncements that require or permit fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Duke Energy is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position

SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans,an amendment to of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of Other Comprehensive Income (OCI), net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Duke Energy is required to initially recognize the funded status of its defined benefit pension and other postretirement plans and to provide the required additional disclosures as of December 31, 2006. Retrospective application is not permitted. Duke Energy anticipates that adoption of SFAS No. 158 recognition and disclosure provisions will result in a decrease in total assets of approximately $175 million, an increase in total liabilities of approximately $418 million and a decrease in accumulated other comprehensive income, net of tax, of approximately $593 million as of December 31, 2006. Duke Energy does not anticipate the adoption of SFAS No. 158 will have any material impact on its consolidated results of operations or cash flows.

Under the measurement date requirements of SFAS No. 158, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Duke Energy has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. The measurement date requirement is effective for the year ending December 31, 2008, and early application is encouraged. Duke Energy intends to adopt the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. Net periodic benefit cost for the three-month period between September 30, 2006 and December 31, 2006 will be recognized, net of tax, as a separate adjustment of retained earnings as of January 1, 2007, except for any gain or loss arising from curtailments or settlements, if any, during that three-month period, which would be recognized in earnings in 2006. Additionally, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost will be recognized, net of tax, as an adjustment to Other Comprehensive Income (OCI).

Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No 108). In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement—including the reversing

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effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN No. 48). On July 13, 2006, the FASB issued FIN No. 48, which interprets SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 provides guidance for the recognition, measurement, classification and disclosure of the financial statement effects of a position taken or expected to be taken in a tax return (“tax position”). The financial statement effects of a tax position must be recognized when there is a likelihood of more than 50 percent that based on the technical merits, the position will be sustained upon examination and resolution of the related appeals or litigation processes, if any. A tax position that meets the recognition threshold must be measured initially and

subsequently as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Interpretation is effective for Duke Energy as of January 1, 2007. Duke Energy is currently evaluating the impact of adopting FIN No. 48, and cannot currently estimate the impact of FIN No. 48 on its consolidated results of operations, cash flows or financial position.

FASB Staff Position (FSP) No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Energy as of January 1, 2007. Duke Energy is currently evaluating the impact of adopting FSP No. FAS 123(R)-5 and cannot currently estimate the impact of adopting FAS 123(R)-5 on its consolidated results of operations, cash flows or financial position.

FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP AUG AIR-1).In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Duke Energy as of January 1, 2007 and will be applied and retrospectively for all financial statements presented. Duke Energy does not anticipate the adoption of FSP No. AUG-AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

Emerging Issues Task Force (EITF) Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis.

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The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations.

Subsequent Events

For information on subsequent events related to acquisitions and dispositions, common stock, debt and credit facilities, severance, discontinued operations and assets held for sale, risk management instruments, regulatory matters, commitments and contingencies and related party transactions, see Note 2, “Acquisitions and Dispositions,” Note 4, “Common Stock,” Note 7, “Debt and Credit Facilities,” Note 11, “Severance,” Note 13, “Discontinued Operations and Assets Held For Sale,” Note 15, “Risk Management Instruments,” Note 16, “Regulatory Matters,” Note 17, “Commitments and Contingencies,” and Note 19, “Related Party Transactions,” 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, 2005.

Commodity Price Risk

Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options.

Duke Energy’s largest commodity exposure is due to market price fluctuations of NGLs primarily in the Field Services segment and, to a lesser extent, in the Natural Gas Transmission segment. Based on a sensitivity analysis as of September 30, 2006, it was estimated that a price change of fifteen cents per gallon in the price of NGLs (net of related hedges and an equivalent price change in crude oil) would have a corresponding effect on pre-tax income from continuing operations of approximately $157 million over the next 12 months. Comparatively, a fifteen cent price change sensitivity analysis as of December 31, 2005 would have impacted pre-tax income from continuing operations by approximately $105 million over the next 12 months. The increase is due primarily to the NGL production after December 31, 2006 being included in the September 30, 2006 sensitivity which is currently not hedged.

Normal Purchases and Normal Sales. During 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 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. Duke Energy retained the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation and combined them with Cinergy’s commercial operations in the Midwest (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” for further details on the Cinergy merger).

Trading and Undesignated Portfolio Risk. Duke Energy’s current energy marketing and trading activities principally consist of the Cinergy commercial marketing and trading business’ natural gas marketing and trading operations and Duke Energy Ohio’s power marketing and trading operations. In June 2006, Duke Energy announced it had reached an agreement to sell the Cinergy marketing and trading business (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The sale closed in

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October 2006. In connection with the sale transaction, Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled as the underlying contracts are transferred to Fortis.

Duke Energy’s domestic operations market and trade over-the-counter (an informal market where the buying/selling of commodities occurs) contracts for the purchase and sale of electricity (primarily in the midwest region of the United States), natural gas, and other energy-related products, including coal and emission allowances. Duke Energy’s natural gas domestic operations provide services that manage storage, transportation, gathering and processing activities. In addition, Duke Energy’s domestic operations market and trade natural gas and other energy-related products on the New York Mercantile Exchange.

Natural gas marketing and trading operations also extend to Canada where natural gas marketing and management services are provided to producers and industrial customers. Duke Energy’s Canadian operations also market and trade over-the-counter contracts as well as energy-related products on the New York Mercantile Exchange.

Many of these energy commodity contracts commit Duke Energy to purchase or sell electricity, natural gas, and other energy-related products at fixed prices in the future. The majority of the contracts in the natural gas and other energy-related products portfolios are financially settled contracts (i.e., there is no physical delivery related with these items). Duke Energy’s risk management policies contain limits associated with the overall size of net open positions for each trading operation.

Once Duke Energy completes its announced exit from the Cinergy commercial marketing and trading business (which have been classified as discontinued operations), its exposure to movements in the price of electricity and other energy commodities will be reduced and, as a result, may lead to decreased future earnings volatility.

Duke Energy currently measures the market risk inherent in the trading portfolio, employing value at risk (VaR) analysis and other methodologies, which utilize forward price curves in electric power and natural gas markets to quantify estimates of the magnitude and probability of future value changes related to open contract positions. Subsequent to the merger with Cinergy, Duke Energy adopted a VaR methodology for disclosure purposes, in line with how Duke Energy currently manages the portfolio. VaR is a statistical measure used to quantify the potential change in the economic value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to market movement. Duke Energy, through some of its non-regulated subsidiaries, markets and trades physical natural gas and electricity and trades derivative commodity instruments which are usually settled in cash including: forwards, futures, swaps, and options.

Any proprietary trading transaction, whether settled physically or financially, is included in the VaR calculation. VaR is reported based on a 95 percent confidence interval, utilizing a one-day holding period. This means that on a given day (one-day holding period) there is a 95 percent chance (confidence level) that Duke Energy’s trading portfolio will not lose more than the stated amount. VaR is measured using a Monte Carlo simulation methodology that considers implied forward-looking volatilities and historical 21 day correlations. Duke Energy’s VaR amounts for commodity derivatives recorded using the mark-to-market model of accounting are shown in the following table.

Value at Risk


	September 30, 2006 One-Day Impact on Pre-tax Income from Continuing Operations for 2006	Estimated Average One-Day Impact on Pre-tax Income from Continuing Operations for Third Quarter 2006	High One-Day Impact on Pre-tax Income from Continuing Operations for Third Quarter 2006	Low One-Day Impact on Pre-tax Income from Continuing Operations for Third Quarter 2006
(	(in millions)
Calculated VaR	$3	$4	$6	$2

(1)	The VaR 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”).

(2)	DENA VaR at September 30, 2006 was not material.

(3)	VaR primarily represents earnings volatility associated with Cinergy Marketing and Trading, LP which was sold in October 2006.

Duke Energy historically used daily earnings at risk (DER) to measure and monitor the mark-to-market portfolio’s impact on earnings. 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.

PART I

Duke Energy disclosed a DER of $12 million as of December 31, 2005, which was primarily comprised of DENA derivative positions. DENA’s DER at September 30, 2006 was zero due to the DENA wind-down. The DER figures 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. The calculated consolidated DER at December 31, 2005 consists of approximately $11 million related to discontinued operations and less than $1 million related to continuing operations.

DETM, the 60%/40% unregulated joint venture with Exxon Mobil continues to prudently manage down its legacy natural gas positions. While the venture was originally created to actively trade and market natural gas following de-regulation, the venture is a very different business today. No active trading is occurring now other than transacting to meet contractual obligations and to optimize remaining legacy gas positions. These legacy positions do not generate any material earnings volatility for Duke Energy.

Generation Portfolio Risks. Duke Energy optimizes the value of its non-regulated portfolio. The portfolio includes generation assets (power and capacity), fuel, and emission allowances. Modeled forecasts of future generation output, fuel requirements, and emission allowance requirements are based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on this model in order to manage the economic value of the portfolio. With the issuance of SFAS No. 149,“Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149), most forward power transactions and certain coal transactions from management of the portfolio are accounted for at fair value. The other component pieces of the portfolio are

typically not subject to SFAS 149 and are accounted for using the accrual method, where changes in fair value are not recognized. As a result, these forward sales and purchases are subject to earnings volatility via mark-to-market gains or losses from changes in the value of the contracts accounted for using fair value. In addition, the generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations. This is primarily related to the Midwestern generation assets retained from DENA. A spark spread sensitivity on these MWH was immaterial at September 30, 2006.

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 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.

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 (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross exposure under the guarantee obligation as of September 30, 2006 is approximately $200 million, which includes principal and interest. Duke Energy does not believe a loss under the guarantee obligation is probable as of September 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of September 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Duke Energy in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms.

PART I

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Duke Energy in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the chief executive officer and chief financial officer, Duke Energy has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2006, and, based upon this evaluation, the chief executive officer and chief financial officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the chief executive officer and chief financial officer, Duke Energy has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2006 and, other than the Duke Energy and Cinergy merger discussed below, found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated. Duke Energy is currently in the process of integrating Cinergy’s operations and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Notes 1, 2 and 14 to the Consolidated Financial Statements for additional information relating to the merger.

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 2006, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Item 1A. Risk Factors

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in Duke Energy’s and Cinergy’s Annual Reports on Form 10-K for the year ended December 31, 2005, as have been updated in Duke Energy’s Quarterly Reports on Form 10-Q for the periods ended March 31, 2006 and June 30, 2006, which could materially affect Duke Energy’s financial condition or future results. Additional risks and uncertainties not currently known to Duke Energy or that Duke Energy currently deems to be immaterial also may materially adversely affect Duke Energy’s financial condition and/or results of operations.

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

Issuer Purchases of Equity Securities for Third Quarter of 2006

There were no issuer purchases of equity securities during the third quarter of 2006.

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment, primarily due to the merger with Cinergy. At the time of suspension, Duke Energy had repurchased 32.6 million shares of common stock for approximately $0.9 billion. During the first quarter of 2006, Duke Energy announced the commencement of up to $1 billion of additional share repurchases under the previously announced plan. During the first six months of 2006, Duke Energy repurchased approximately 17.5 million shares of common stock for approximately $0.5 billion. In June 2006, in connection with the plan to spin off Duke Energy’s natural gas businesses to Duke Energy shareholders, the share repurchase program has since been suspended. At the time of suspension, Duke Energy has repurchased approximately 50 million shares of common stock for approximately $1.4 billion under this repurchase plan. The dollar value of shares that may yet be purchased under the plan as of September 30, 2006 is approximately $1.1 billion.

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

No matters were submitted to a vote of Duke Energy’s security holders during the third quarter of 2006.

PART II.

Item 6. Exhibits

(a) Exhibits

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


Exhibit Number
10.1**		Form of Amendment to Performance Award Agreement and Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as exhibit 10.1).

10.2**		Form of Amendment to Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as exhibit 10.2).

*10.3		Formation and Sale Agreement by and among Duke Ventures, LLC, Crescent Resources, LLC, Morgan Stanley Real Estate Fund V U.S. L.P., Morgan Stanley Real Estate Fund V Special U.S., L.P., Morgan Stanley Real Estate Investors V U.S., L.P., MSP Real Estate Fund V, L.P., and Morgan Stanley Strategic Investments, Inc., dated as of September 7, 2006.

*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.

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, 2006				/s/ DAVID L. HAUSER
				David L. Hauser Group Executive and Chief Financial Officer

Date: November 9, 2006				/s/ STEVEN K. YOUNG
				Steven K. Young Vice President and Controller

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Duke Energy (DUK) 10-Q2006 Q3 Quarterly report

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