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 June 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. Yes x 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 filer x                 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 August 4, 2006 1,253,011,563

INDEX

DUKE ENERGY CORPORATION

FORM 10-Q FOR THE QUARTER ENDED

JUNE 30, 2006

Item		Page
PART I. FINANCIAL INFORMATION
1.	Financial Statements	3
	Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005 .	3
	Unaudited Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005	4
	Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005	6
	Unaudited Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2006 and 2005	7
	Unaudited Notes to Consolidated Financial Statements	8
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
3.	Quantitative and Qualitative Disclosures About Market Risk	70
4.	Controls and Procedures	72
PART II. OTHER INFORMATION
1.	Legal Proceedings	73
1A.	Risk Factors	73
2.	Unregistered Sales of Equity Securities and Use of Proceeds	73
4.	Submission of Matters to a Vote of Security Holders	73
6.	Exhibits	74
	Signatures	76

SAFE HARBOR STATEMENT UNDER THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

Duke Energy Corporation’s (Duke Energy) reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Energy’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Energy’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include the risk factors set forth in Item 1A of the Form 10-K of Duke Energy and of Cinergy Corp. (Cinergy) for the year ended December 31, 2005, as updated in their respective Form 10-Q for the period ended March 31, 2006, as well as the following:

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

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

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

• 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

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

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

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

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

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

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

• Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop 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

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

• The ability to successfully complete merger, acquisition or divestiture plans, including the 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)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	985		$	3,305		$	1,581		$	6,206
Regulated electric		2,030			1,226			3,316			2,485
Regulated natural gas and natural gas liquids		958			743			2,277			1,911
Total operating revenues		3,973			5,274			7,174			10,602
Operating Expenses
Natural gas and petroleum products purchased		431			2,613			1,169			5,363
Operation, maintenance and other		1,195			894			1,952			1,702
Fuel used in electric generation and purchased power		971			392			1,370			741
Depreciation and amortization		564			462			960			943
Property and other taxes		202			145			350			298
Impairment and other charges		—			2			—			123
Total operating expenses		3,363			4,508			5,801			9,170
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		145			12			171			54
(Losses) Gains on Sales of Other Assets and Other, net		(11	)		—			22			9
Operating Income		744			778			1,566			1,495
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		194			39			369			80
(Losses) Gains on sales and impairments of equity investments		(20	)		6			(20	)		1,245
Other income and expenses, net		46			35			58			59
Total other income and expenses		220			80			407			1,384
Interest Expense		339			295			589			585
Minority Interest Expense		15			78			30			498
Earnings From Continuing Operations Before Income Taxes		610			485			1,354			1,796
Income Tax Expense from Continuing Operations		175			157			433			608
Income From Continuing Operations		435			328			921			1,188
Loss From Discontinued Operations, net of tax		(80	)		(19	)		(208	)		(11	)
Net Income		355			309			713			1,177
Dividends and Premiums on Redemption of Preferred and Preference Stock		—			2			—			4
Earnings Available For Common Stockholders	$	355		$	307		$	713		$	1,173
Common Stock Data
Weighted-average shares outstanding
Basic		1,238			927			1,083			941
Diluted		1,259			964			1,111			977
Earnings per share (from continuing operations)
Basic	$	0.35		$	0.35		$	0.85		$	1.26
Diluted	$	0.34		$	0.34		$	0.83		$	1.21
Loss per share (from discontinued operations)
Basic	$	(0.06	)	$	(0.02	)	$	(0.19	)	$	(0.01	)
Diluted	$	(0.06	)	$	(0.02	)	$	(0.19	)	$	(0.01	)
Earnings per share
Basic	$	0.29		$	0.33		$	0.66		$	1.25
Diluted	$	0.28		$	0.32		$	0.64		$	1.20
Dividends per share	$	0.63		$	0.585		$	0.94		$	0.86

See Notes to Unaudited Consolidated Financial Statements

3

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	June 30, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	752	$	511
Short-term investments		254		632
Receivables (net of allowance for doubtful accounts of $161 at June 30, 2006 and $127 at December 31, 2005)		2,253		2,580
Inventory		1,201		863
Assets held for sale		1,309		1,528
Unrealized gains on mark-to-market and hedging transactions		93		87
Other		953		1,756
Total current assets		6,815		7,957
Investments and Other Assets
Investments in unconsolidated affiliates		2,516		1,933
Nuclear decommissioning trust funds		1,588		1,504
Goodwill		8,042		3,775
Intangibles, net		1,048		65
Notes receivable		268		138
Unrealized gains on mark-to-market and hedging transactions		154		62
Assets held for sale		635		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $18 at June 30, 2006 and $17 at December 31, 2005)		1,382		1,281
Other		3,140		2,678
Total investments and other assets		18,773		15,033
Property, Plant and Equipment
Cost		57,340		40,823
Less accumulated depreciation and amortization		16,445		11,623
Net property, plant and equipment		40,895		29,200
Regulatory Assets and Deferred Debits
Deferred debt expense		331		269
Regulatory assets related to income taxes		1,356		1,338
Other		2,198		926
Total regulatory assets and deferred debits		3,885		2,533
Total Assets	$	70,368	$	54,723

See Notes to Unaudited Consolidated Financial Statements

4

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

(In millions, except per-share amounts)

	June 30, 2006		December 31, 2005
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,470	$	2,431
Notes payable and commercial paper		1,272		83
Taxes accrued		487		327
Interest accrued		306		230
Liabilities associated with assets held for sale		885		1,488
Current maturities of long-term debt		1,371		1,400
Unrealized losses on mark-to-market and hedging transactions		250		204
Other		2,029		2,255
Total current liabilities		8,070		8,418
Long-term Debt		18,574		14,547
Deferred Credits and Other Liabilities
Deferred income taxes		7,076		5,253
Investment tax credit		226		144
Unrealized losses on mark-to-market and hedging transactions		117		10
Liabilities associated with assets held for sale		444		2,085
Asset retirement obligations		2,185		2,058
Other		7,261		5,020
Total deferred credits and other liabilities		17,309		14,570
Commitments and Contingencies
Minority Interests		745		749
Common Stockholders’ Equity
Common stock, $0.001 par value, 2 billion shares authorized; 1,252 million and zero shares outstanding at June 30, 2006 and December 31, 2005, respectively		1		—
Common stock, no par, 2 billion shares authorized; zero and 928 million shares outstanding at June 30, 2006 and December 31, 2005, respectively		—		10,446
Additional paid-in capital		19,715		—
Retained earnings		4,907		5,277
Accumulated other comprehensive income		1,047		716
Total common stockholders’ equity		25,670		16,439
Total Liabilities and Common Stockholders’ Equity	$	70,368	$	54,723

See Notes to Unaudited Consolidated Financial Statements

5

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Six Months Ended June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	713		$	1,177
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,042			1,081
Gains on sales of investments in commercial and multi-family real estate		(171	)		(54	)
Gains on sales of equity investments and other assets		(6	)		(1,281	)
Impairment charges		20			123
Deferred income taxes		301			244
Minority Interest		30			484
Equity in earnings of unconsolidated affiliates		(369	)		(80	)
Purchased capacity levelization		(4	)		(5	)
Contribution to company-sponsored pension plans		(23	)		(21	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(153	)		17
Receivables		1,182			286
Inventory		144			(11	)
Other current assets		1,249			(46	)
Increase (decrease) in
Accounts payable		(1,730	)		(175	)
Taxes accrued		(57	)		332
Other current liabilities		(1,138	)		(65	)
Capital expenditures for residential real estate		(240	)		(209	)
Cost of residential real estate sold		86			109
Other, assets		471			(106	)
Other, liabilities		97			228
Net cash provided by operating activities		1,444			2,028
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(1,393	)		(1,062	)
Investment expenditures		(63	)		(24	)
Acquisitions, net of cash acquired		(89	)		—
Cash acquired from acquisition of Cinergy		147			—
Purchases of available-for-sale securities		(13,479	)		(20,787	)
Proceeds from sales and maturities of available-for-sale securities		13,705			20,987
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,597			1,341
Proceeds from the sales of commercial and multi-family real estate		221			77
Settlement of net investment hedges and other investing derivatives		(89	)		(162	)
Purchases of emission allowances		(112	)		—
Sales of emission allowances		82			—
Other		(60	)		(8	)
Net cash provided by investing activities		467			362
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		335			4
Issuance of common stock and common stock related to employee benefit plans		41			28
Payments for the redemption of:
Long-term debt		(1,014	)		(639	)
Preferred stock of a subsidiary		(12	)		—
Increase in overdrafts		24			—
Notes payable and commercial paper		170			167
Distributions to minority interests		(231	)		(377	)
Contributions from minority interests		184			330
Dividends paid		(681	)		(522	)
Repurchase of common shares		(500	)		(909	)
Other		14			3
Net cash used in financing activities		(1,670	)		(1,915	)
Changes in cash and cash equivalents included in assets held for sale		—			1
Net increase in cash and cash equivalents		241			476
Cash and cash equivalents at beginning of period		511			533
Cash and cash equivalents at end of period	$	752		$	1,009
Supplemental Disclosures
Acquisition of Cinergy Corp.
Fair value of assets acquired	$	17,638		$	—
Liabilities assumed	$	12,838		$	—
Issuance of common stock	$	8,993		$	—
Significant non-cash transactions:
Conversion of convertible notes to stock	$	611		$	—
Dividends declared but not paid	$	402		$	287
AFUDC—equity component	$	26		$	9

See Notes to Unaudited Consolidated Financial Statements

6

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	—			—			—			868			—		—			—			—			868
Other Comprehensive Income
Foreign currency translation adjustments (a)	—			—			—			—			47		—			—			—			47
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		143			—			—			143
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		59			—			—			59
Total comprehensive income																								1,117
Dividend reinvestment and employee benefits	1			25			—			—			—		—			—			—			25
Stock repurchase	(30	)		(834	)		—			—			—		—			—			—			(834	)
Common stock dividends	—			—			—			(263	)		—		—			—			—			(263	)
Preferred and preference stock dividends	—			—			—			(2	)		—		—			—			—			(2	)
Balance March 31, 2005	928		$	10,457		$	—		$	5,128		$	587	$	728		$	(416	)	$	—		$	16,484
Net income	—			—			—			309			—		—			—			—			309
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			9		—			—			—			9
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		93			—			—			93
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		(57	)		—			—			(57	)
Total comprehensive income																								354
Dividend reinvestment and employee benefits	1			30			—			—			—		—			—			—			30
Stock repurchase	(3	)		(75	)		—			—			—		—			—			—			(75	)
Common stock dividends	—			—			—			(542	)		—		—			—			—			(542	)
Preferred and preference stock dividends	—			—			—			(2	)		—		—			—			—			(2	)
Other capital stock transactions, net	—			—			—			32			—		—			—			—			32
Balance June 30, 2005	926		$	10,412		$	—		$	4,925		$	596	$	764		$	(416	)	$	—		$	16,281
Balance December 31, 2005	928		$	10,446		$	—		$	5,277		$	846	$	(87	)	$	(60	)	$	17		$	16,439
Net income	—			—			—			358			—		—			—			—			358
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			59		—			—			—			59
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		5			—			—			5
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		11			—			—			11
Other (d)	—			—			—			—			—		—			—			16			16
Total comprehensive income																								449
Dividend reinvestment and employee benefits	1			22			—			—			—		—			—			—			22
Stock repurchase	(2	)		(69	)		—			—			—		—			—			—			(69	)
Common stock dividends	—			—			—			(289	)		—		—			—			—			(289	)
Balance March 31, 2006	927		$	10,399		$	—		$	5,346		$	905	$	(71	)	$	(60	)	$	33		$	16,552
Net income	—			—			—			355			—		—			—			—			355
Other Comprehensive Income
Foreign currency translation adjustments	—			—						—			252		—			—			—			252
Net unrealized losses on cash flow hedges (b)	—			—			—			—			—		(8	)		—			—			(8	)
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		6			—			—			6
Other (d)	—			—			—			—			—		—			—			(10	)		(10	)
Total comprehensive income																								595
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	1			—			50			—			—		—			—			—			50
Stock repurchase	(15	)		—			(431	)		—			—		—			—			—			(431	)
Common stock dividends	—			—			—			(794	)		—		—			—			—			(794	)
Conversion of debt to equity	26			—			611			—			—		—			—			—			611
Tax benefit due to conversion of debt to equity	—			—			32			—			—		—			—			—			32
Other capital stock transactions, net	—			—			3			—			—		—			—			—			3
Balance June 30, 2006	1,252		$	1		$	19,715		$	4,907		$	1,157	$	(73	)	$	(60	)	$	23		$	25,670

(a) Foreign currency translation adjustments, net of $62 tax benefit for the three months ended March 31, 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 $9 tax benefit and $49 tax expense for the three months ended June 30, 2006 and 2005, respectively, and $3 and $74 tax expense for the three months ended March 31, 2006 and 2005, respectively.

(c) Reclassification into earnings from cash flow hedges, net of $7 tax expense and $29 tax benefit for the three months ended June 30, 2006 and 2005, respectively, and $7 and $30 tax expense for the three months ended March 31, 2006 and 2005, respectively. Reclassification into earnings from cash flow hedges for the three months ended March 31, 2006, is due primarily to the recognition of Duke Energy North America’s (DENA’s) unrealized net gains related to hedges on forecasted transactions which will no longer occur as a result of the plan to sell or otherwise dispose of substantially all of DENA’s assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 13 and 15).

(d) Net of $4 tax benefit for the three months ended June 30, 2006, and $8 tax expense for the three months ended March 31, 2006.

See Notes to Unaudited Consolidated Financial Statements

7

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

(Unaudited)

1. Basis of Presentation

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

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. 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 six months ended June 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 (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.

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. 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.

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 Cash Flows have been reclassified to conform to the presentation for the current period.

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Notes To Consolidated Financial Statements—(Continued)

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 six months ended June 30, 2006 and 2005 were as follows:

	Three Months Ended June 30, 2006		Three Months Ended June 30, 2005		Six Months Ended June 30, 2006		Six Months Ended June 30, 2005
	(in millions)
Excise Taxes	$	61	$	27	$	91	$	56

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 EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available 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 is anticipated to provide 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 merger date. Except for an adjustment related to pension and other postretirement benefit obligations, as mandated by Statement of Financial 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 The Cincinnati Gas & Electric Company’s (CG&E) regulated transmission and distribution, PSI Energy, Inc. (PSI) and 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 $4.3 billion. The amount of goodwill results from significant strategic and financial benefits to the company 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;

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Notes To Consolidated Financial Statements—(Continued)

• 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	$	9,089
Current assets		2,642
Investments and other assets		1,610
Property, plant and equipment(a)		10,897
Intangible assets		1,092
Regulatory assets and deferred debits		1,397
Total assets acquired		17,638
Current liabilities		4,132
Long-term debt		4,295
Deferred credits and other liabilities		4,400
Minority interests		11
Net assets acquired		4,800
Preliminary goodwill	$	4,289

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

Goodwill recorded as of June 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,289 million, none of which is deductible for income tax purposes. Of this amount, approximately $161 million has been allocated to assets held for sale related to the disposition of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (see Note 13). 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 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, and the majority of the goodwill will be 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 June 30, 2005		Six Months Ended June 30,
			2006		2005
	(in millions, except per share amounts)
Operating revenues	$	6,329	$	8,819	$	12,911
Income from continuing operations		347		955		1,268
Net income		333		765		1,291
Earnings available for common stockholders		331		765		1,287
Earnings per share (from continuing operations)
Basic	$	0.28	$	0.77	$	1.01
Diluted	$	0.27	$	0.75	$	0.99
Earnings per share
Basic	$	0.27	$	0.61	$	1.03
Diluted	$	0.26	$	0.60	$	1.00

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Pro forma results for the six months ended June 30, 2006 include approximately $78 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 June 30, 2006 are not presented since the merger occurred at 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 $130 million to $140 million during 2006.

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 65% 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, which had been classified as Assets Held For Sale, 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 Westinghouse 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 over the next twenty years. The transaction, which is anticipated to close in the fourth quarter of 2006, requires approvals by the North Carolina Utilities Commission (NCUC) and the Federal Energy Regulatory Commission (FERC). In addition, approval is required from either the 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 is pending.

Dispositions. For the three months ended June 30, 2006, the sale of other assets and businesses resulted in approximately $8 million in proceeds and net pre-tax losses of $11 million recorded in (Losses) Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. For the six months ended June 30, 2006, the sale of other assets and businesses resulted in approximately $36 million in proceeds and net pre-tax gains of $22 million recorded in (Losses) 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 Resources LLC (Crescent) which are discussed separately below. Significant sales of other assets during the six months ended June 30, 2006 are detailed as follows:

• 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 (Losses) 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 (Losses) 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 three months ended June 30, 2006, Crescent commercial and multi-family real estate sales resulted in $165 million of proceeds and $145 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2006, Crescent commercial and multi-family real estate sales resulted in $221 million of proceeds and $171 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 primarily consisted of two office buildings at Potomac Yard

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Notes To Consolidated Financial Statements—(Continued)

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 June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $13 million in proceeds, and pre-tax gains of $6 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. For the six months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $1.2 billion in proceeds, net pre-tax gains of $9 million recorded in (Losses) 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 June 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 six months ended June 30, 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which have been classified as (Losses) Gains on Sales of Other Assets and Other, Net in the Consolidated Statement of Operations for the six months ended June 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the six months ended June 30, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

• Additional asset and business sales during the six month period ended June 30, 2005 total approximately $20 million in proceeds. These sales resulted in net pre-tax gains of $9 million which were recorded in (Losses) Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations.

For the three months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $26 million of proceeds and $12 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $77 million of proceeds and $54 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales consisted of several “legacy” land sales.

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.

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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 six months ended June 30, 2006 and 2005.

	Income			Average     Shares	EPS
	(in millions, except per-share data)
Three Months Ended June 30, 2006
Income from continuing operations	$	435
Less: Dividends and premiums on redemption of preferred and preference stock		—
Income from continuing operations—basic	$	435		1,238	$	0.35
Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		1		17
Income from continuing operations—diluted	$	436		1,259	$	0.34
Three Months Ended June 30, 2005
Income from continuing operations	$	328
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)
Income from continuing operations—basic	$	326		927	$	0.35
Effect of dilutive securities:
Stock options, phantom, performance and unvested stock, and common stock derivatives				4
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	328		964	$	0.34
Six Months Ended June 30, 2006
Income from continuing operations	$	921
Less: Dividends and premiums on redemption of preferred and preference stock		—
Income from continuing operations—basic	$	921		1,083	$	0.85
Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		3		24
Income from continuing operations—diluted	$	924		1,111	$	0.83
Six Months Ended June 30, 2005
Income from continuing operations	$	1,188
Less: Dividends and premiums on redemption of preferred and preference stock		(4	)
Income from continuing operations—basic	$	1,184		941	$	1.26
Effect of dilutive securities:
Stock options, phantom, performance and unvested stock, and common stock derivatives				3
Contingently convertible bond		4		33
Income from continuing operations—diluted	$	1,188		977	$	1.21

The increase in weighted-average shares outstanding for the three and six months ended June 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 26 million shares of Duke Energy common stock during the second quarter of 2006 (see Note 4), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the six months ended June 30, 2006, of which 2.4 million shares were repurchased in the first quarter of 2006 and 15.1 million shares were repurchased in the second quarter of 2006 (see Note 4).

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Options, unvested stock, performance and phantom stock awards related to approximately 20 million shares as of June 30, 2006 and 18 million shares as of June 30, 2005 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 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 three and six months ended June 30, 2006, Duke Energy repurchased 15.1 million and 17.5 million shares, respectively, for total consideration of approximately $430 million and $500 million, respectively. 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 (see “Executive Overview” section of “Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition.”)

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. 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. Total consideration paid to repurchase the shares of approximately $909 million, including commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital.

In April 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. Holders of the convertible debt were able to exercise their right to convert on or prior to June 30, 2006. During the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy common stock. At June 30, 2006, the balance of the convertible debt is approximately $131 million and remains convertible in the third quarter of 2006 into approximately 5.6 million shares of Duke Energy common stock.

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 has approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

As of June 30, 2006 and December 31, 2005, approximately $402 million and $0, respectively, of dividends payable were included in Other within Current Liabilities within the Consolidated Balance Sheets. At June 30, 2006, this balance exceeded 5% of total current liabilities.

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

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Notes To Consolidated Financial Statements—(Continued)

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 stock-based compensation expense for the three and six months ended June 30, 2006 and 2005 as follows, the components of which are further described below:

	Three Months Ended June 30				Six Months Ended June 30
	2006		2005		2006		2005
	(in millions)
Stock Options	$	3	$	—	$	5	$	—
Stock Appreciation Rights		—		1		1		1
Phantom Stock		16		6		20		10
Performance Awards		7		7		12		14
Other Stock Awards		1		—		1		1
Total	$	27	$	14	$	39	$	26

The tax benefit associated with the recorded expense for the six months ended June 30, 2006 and 2005 was approximately $15 million and $10 million, respectively. There were no material differences in income from continuing operations, income from income taxes, 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.

Pro Forma Stock-Based Compensation

	Three months ended June 30, 2005			Six months ended June 30, 2005
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	307		$	1,173
Add: stock-based compensation expense included in reported net income, net of related tax effects		9			16
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(9	)		(16	)
Pro forma earnings available for common stockholders, net of related tax effects	$	307		$	1,173
Earnings per share
Basic—as reported	$	0.33		$	1.25
Basic—pro forma	$	0.33		$	1.25
Diluted—as reported	$	0.32		$	1.20
Diluted—pro forma	$	0.32		$	1.20

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, 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.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Upon the acquisition of Cinergy, Duke Energy converted all stock options outstanding under the Cinergy Long-Term Incentive 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)	9,155			24
Exercised	(2,061	)		21
Forfeited or expired	(706	)		30
Outstanding at June 30, 2006	31,894			29	5.2	$	131
Exercisable at June 30, 2006	26,908		$	30	4.6		96

(a) Includes 7,277,522 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 six months ended June 30, 2006 and 2005 was approximately $17 million and $13 million, respectively. Cash received from options exercised during the six months ended June 30, 2006 was approximately $42 million, with a related tax benefit of approximately $6 million.

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 six months ended June 30, 2006. There were no options grants 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 1,531,700 shares (fair value of approximately $31 million) in the six months ended June 30, 2006, and 1,273,830 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the six months ended June 30, 2005.

16

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following table summarizes information about stock-based performance awards outstanding at June 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	1,531,700			20
Vested	(114,000	)		27
Forfeited	(206,213	)		26
Canceled	—			—
Outstanding at June 30, 2006	4,152,255			23

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $3 million. As of June 30, 2006, Duke Energy had approximately $46 million of compensation expense which is expected to be recognized over a weighted-average period of 1.5 years.

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,096,580 shares (fair value of approximately $32 million) based on the market price of Duke Energy’s common stock at the grant dates in the six months ended June 30, 2006, and 1,138,930 shares (fair value of approximately $31 million) in the six months ended June 30, 2005. Converted Cinergy phantom stock awards are paid in cash and are measured and recorded as liability awards.

The following table summarizes information about phantom stock awards outstanding at June 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)	1,128,110			29
Vested	(592,618	)		25
Forfeited	(135,103	)		26
Canceled	—			—
Outstanding at June 30, 2006	2,917,409			27

(b) Includes 31,530 converted Cinergy awards

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $15 million and $7 million, respectively. As of June 30, 2006, Duke Energy had approximately $38 million of compensation expense 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 six months ended June 30, 2006, and 35,000 shares (fair value of approximately $1 million) in the six months ended June 30, 2005.

The following table summarizes information about other stock awards outstanding at June 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 June 30, 2006	438,707			27

(c) Includes 50,980 converted Cinergy awards

17

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $2 million and $1 million, respectively. As of June 30, 2006, Duke Energy had approximately $10 million of compensation expense which is expected to be recognized over a weighted-average period of 3.3 years.

6. Inventory

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

Inventory

	June 30, 2006		December 31, 2005
	(in millions)
Materials and supplies	$	583	$	434
Natural gas		218		269
Coal held for electric generation		356		115
Petroleum products		44		45
Total inventory	$	1,201	$	863

7. Debt and Credit Facilities

As discussed in Note 4, in April 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 the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy Common Stock.

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

In June 2006, PSI 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, ULH&P issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance will be used to refund a like amount of debt on September 1, 2006 currently outstanding at CG&E. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

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 six months ended June 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $764 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 reflect Duke Energy’s reduced liquidity needs as a result of exiting the DENA business (see Note 13).

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 June 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.

18

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As of June 30, 2006, approximately $323 million of Cinergy Pollution Control notes were classified in Notes Payable and Commercial Paper in the Consolidated Balance Sheets.

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

				Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Power Company LLC
$500 multi-year syndicated(a), (b), (c)	June 2011
$150 364-day bi-lateral(a), (b)	September 2006
Total Duke Power Company LLC		$	650	$	300	$	—	$	300
Duke Capital LLC
$600 multi-year syndicated(a), (b), (d)	June 2010
$130 three-year bi-lateral(b)	October 2007
$120 multi-year bi-lateral(b)	July 2009
Total Duke Capital LLC			850		—		372		372
Westcoast Energy Inc.
$180 multi-year syndicated(c), (e)	June 2011		180		—		—		—
Union Gas Limited
$360 364-day syndicated(f)	June 2007		360		—		—		—
Cinergy Corp.
$2,000 multi-year syndicated(a), (b), (g)	June 2011		2,000		949		93		1,042
Total(h)		$	4,040	$	1,249	$	465	$	1,714

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

(e) 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%.

(f) 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.

(g) Contains $500 million sub limits each for CG&E and PSI. In June 2006, the credit facility expiration date was extended from September 2010 to June 2011.

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

19

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’ U.S. retirement plans and Westcoast Energy, Inc. (Westcoast) Canadian retirement plans. Net periodic pension costs of Cinergy are included in the below tables for the period from the date of acquisition and thereafter.

Components of Net Periodic Pension Costs: Qualified Pension Benefits (Income)
	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost	$	30		$	16		$	47		$	31
Interest cost on projected benefit obligation		66			40			104			79
Expected return on plan assets		(81	)		(57	)		(137	)		(114	)
Amortization of prior service cost		—			(1	)		(1	)		(1	)
Amortization of loss		13			8			27			17
Net periodic pension costs	$	28		$	6		$	40		$	12
Westcoast
Service cost	$	3		$	2		$	6		$	4
Interest cost on projected benefit obligation		8			8			16			15
Expected return on plan assets		(8	)		(7	)		(16	)		(13	)
Amortization of loss		3			1			5			2
Net periodic pension costs	$	6		$	4		$	11		$	8
Components of Net Periodic Pension Costs: Non-Qualified Pension Benefits
	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost	$	1		$	—		$	2		$	—
Interest cost on projected benefit obligation		2			1			3			2
Amortization of prior service cost		1			1			1			1
Amortization of net transition asset		—			—			—			1
Net periodic pension costs	$	4		$	2		$	6		$	4
Westcoast
Service cost	$	—		$	—		$	—		$	—
Interest cost on projected benefit obligation		1			1			2			2
Amortization of loss		—			—			1			—
Net periodic pension costs	$	1		$	1		$	3		$	2

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. Duke Energy has not made contributions to its U.S. retirement plan for the three and six month ended June 30, 2006. Duke Energy expects to make contributions of approximately $120 million to the legacy Cinergy qualified pension plans during the remainder of 2006.

20

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 June 30, 2006 and $21 million for the six months ended June 30, 2006. Duke Energy anticipates that it will make total contributions of approximately $42 million in 2006. Duke Energy has contributed $1 million to the Westcoast DC plans for the three months ended June 30, 2006 and $2 million for the six months ended June 30, 2006, and anticipates that it will make total contributions of approximately $4 million in 2006. Duke Energy has contributed $1 million to the Westcoast non-qualified plans for the three months ended June 30, 2006 and $2 million for the six months ended June 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 June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost benefit	$	4		$	2		$	6		$	3
Interest cost on accumulated post—retirement benefit obligation		17			12			28			23
Expected return on plan assets		(4	)		(5	)		(8	)		(9	)
Amortization of net transition liability		4			4			8			8
Amortization of loss		3			2			5			4
Net periodic post-retirement benefit costs	$	24		$	15		$	39		$	29
Westcoast
Service cost benefit	$	1		$	—		$	2		$	1
Interest cost on accumulated post—retirement benefit obligation		2			1			3			2
Amortization of loss		—			1			1			1
Net periodic post-retirement benefit costs	$	3		$	2		$	6		$	4

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy expensed employer matching contributions of $17 million for the three months ended June 30, 2006 compared to $14 million for the three months ended June 30, 2005. Duke Energy expensed employer matching contributions of approximately $41 million for the six months ended June 30, 2006 compared to $34 million for the six months ended June 30, 2005.

21

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.” 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 $5.4 billion. The following table shows the components of goodwill at June 30, 2006:

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2005		Acquisitions(a)		Other(b)			Balance June 30, 2006
	(in millions)
Natural Gas Transmission	$	3,512	$	—	$	128		$	3,640
International Energy		256		—		11			267
Crescent		7		—		—			7
Unallocated(a)		—		4,289		(161	)		4,128
Total consolidated	$	3,775	$	4,289	$	(22	)	$	8,042

(a) Goodwill recorded as of June 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,289 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 at least half of the goodwill likely relating to the U.S. Franchised Electric and Gas segment.

(b) Primarily relates to foreign currency translation and goodwill allocated to the distribution of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (see Note 13)

Intangible Assets

Intangible assets acquired via merger with Cinergy. In connection with the merger with Cinergy, Duke Energy recorded intangible assets of approximately $1,092 million, primarily relating to approximately $710 million of emission allowances and approximately $370 million of gas, coal and power contracts. Additionally, Duke Energy recorded liabilities associated with other power sale contracts amounting to approximately $66 million.

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

	June 30, 2006			December 31, 2005			Weighted Average Life
				(in millions)
Emission allowances	$	703		$	24		(a	)
Gas, coal and power contracts		320			23		(b	)
Other		57			23		30
Total gross carrying amount		1,080			70
Accumulated amortization—gas, coal and power contracts		(18	)		(1	)
Accumulated amortization—other		(14	)		(4	)
Total accumulated amortization		(32	)		(5	)
Total intangible assets, net	$	1,048		$	65

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

(b) Of this balance, approximately $115 million will be amortized as consumed and does not have a definitive life, and approximately $155 million will be amortized on a straight line basis over 20 years.

22

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Emission allowances, which do not have an expiration date, will be recognized in earnings as they are consumed or sold. Gains or losses on sales of emission allowances are presented on a net basis in Gain (Loss) on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations. The estimated recognition of the acquired value of emission allowances is currently anticipated to be approximately $200 million during the remainder of 2006, $147 million in 2007, $94 million in 2008, $84 million in 2009, $32 million in 2010 and $46 million in 2011. Approximately $115 million of the step-ups in value of gas, coal and power contracts will primarily be recognized in earnings on a consumption basis and are estimated to amount to $20 million for the remainder of 2006, $44 million in 2007, $17 million in 2008, $17 million in 2009, $12 million in 2010 and $5 million in 2011. Approximately $155 million of the step-ups in the value of gas, coal and power contracts relates to a long-term power contract to buy power from a generating company of which Duke Energy owns 9%. The value of this contract will be amortized on a straight-line basis over the current contractual period, which runs through March 2026. Amortization expense for this contract will amount to approximately $5 million for the remainder of 2006 and approximately $8 million in the years 2007 through 2010. Amortization expense for all other intangible assets is estimated to amount to approximately $4 million for the remainder of 2006, $3 million for each of the years 2007 through 2010 and approximately $2 million in 2011.

Additionally, Duke Energy recorded liabilities associated with a rate stabilization plan (RSP) in Ohio that will be recognized in earnings over the remaining regulatory period, which ends on December 31, 2008. Amortization expense related to the RSP is estimated to amount to approximately $4 million for the remainder of 2006, $44 million in 2007 and $67 million in 2008. The liability amounts allocated to other power sale contracts will be amortized to income as follows: $10 million during the remainder of 2006, $17 million in 2007, and approximately $5 million in each of the years 2008 through 2011.

The amortization amounts discussed above 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.

Emission allowances sold or consumed during the three and six months ended June 30, 2006 was $87 million and $95 million, respectively. Emission allowances sold or consumed during the three and six months ended June 30, 2005 was immaterial. Amortization expense for intangible assets for the three months ended June 30, 2006 and 2005 was $6 million and $1 million, respectively. Amortization expense for intangible assets for the six months ended June 30, 2006 and 2005 was approximately $8 million and $1 million, respectively.

10. Marketable Securities

During the six months ended June 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 (Losses) Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations for the six months ended June 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 six months ended June 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 six months ended June 30, 2006.

11. Severance

During the three months ended June 30, 2006, Duke Energy accrued approximately $55 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. Duke Energy does not anticipate any additional material severance liabilities as a result of the merger and payments under existing agreements will occur as the service periods expire. All 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 Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as associated contracts managed by these companies, to Fortis, a Benelux-based financial services group. As such, results of operations for Cinergy Marketing and Trading, LP (CMT), and Cinergy Canada, Inc., have been reflected in Loss from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to June 30, 2006. Duke Energy does not currently anticipate recording material severance liabilities as a result of the disposal of CMT.

23

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA anticipates involuntary termination of approximately 250 employees by 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 June 30, 2006
	(in millions)
U.S. Franchised Electric and Gas	$	—	$	2		$	—		$	2
Natural Gas Transmission		3		(1	)		—			2
Other(a)(b)		28		94			(58	)		64
Total(c)	$	31	$	95		$	(58	)	$	68

(a) Of the $95 million in the provision/adjustments column for the second quarter of 2006, approximately $67 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. During the three months ended June 30, 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 expires on November 7, 2006 and there have been ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA. 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 $14 million, which is 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 three and six months ended June 30, 2006, and a $38 million impairment of notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the Consolidated Statements of Operations for the three and six months ended June 30, 2006.

Field Services. During the six months ended June 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.

24

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 Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

			Operating Loss									Net Loss on Dispositions
	Operating Revenues		Pre-tax Operating (Loss) Gain			Income Tax (Benefit) Expense			Operating Loss, Net of Tax			Pre-tax (Loss) Gain on Dispositions			Income Tax (Benefit) Expense			(Loss) Gain on Dispositions, Net of Tax			(Loss) Gain From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended June 30, 2006
Other(a)	$	143	$	(44	)	$	(15	)	$	(29	)	$	(78	)	$	(28	)	$	(50	)	$	(79	)
International Energy		—		(1	)		(1	)		—			9			4			5			5
Commercial Power		2		(11	)		(3	)		(8	)		(6	)		(8	)		2			(6	)
Total consolidated	$	145	$	(56	)	$	(19	)	$	(37	)	$	(75	)	$	(32	)	$	(43	)	$	(80	)
Three Months Ended June 30, 2005
Other(a)	$	386	$	(27	)	$	—		$	(27	)	$	(1	)	$	(9	)	$	8		$	(19	)
International Energy		—		2			2			—			—			—			—			—
Crescent		1		—			—			—			—			—			—			—
Total consolidated	$	387	$	(25	)	$	2		$	(27	)	$	(1	)	$	(9	)	$	8		$	(19	)
Six Months Ended June 30, 2006
Other(a)	$	489	$	(54	)	$	(8	)	$	(46	)	$	(234	)	$	(85	)	$	(149	)	$	(195	)
International Energy		—		(1	)		(1	)		—			(10	)		(3	)		(7	)		(7	)
Commercial Power		2		(11	)		(3	)		(8	)		(6	)		(8	)		2			(6	)
Total consolidated	$	491	$	(66	)	$	(12	)	$	(54	)	$	(250	)	$	(96	)	$	(154	)	$	(208	)
Six Months Ended June 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Other(a)		877		(25	)		(13	)		(12	)		—			—			—			(12	)
International Energy		—		4			3			1			—			—			—			1
Crescent		1		—			—			—			—			—			—			—
Total consolidated	$	882	$	(21	)	$	(10	)	$	(11	)	$	—		$	—		$	—		$	(11	)

(a) Other includes the results for Duke Energy North America’s (DENA) 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 June 30, 2006 and December 31, 2005.

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

	June 30, 2006		December 31, 2005
	(in millions)
Current assets	$	1,309	$	1,528
Investments and other assets		610		2,059
Property, plant and equipment, net		25		1,538
Total assets held for sale	$	1,944	$	5,125
Current liabilities	$	885	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		444		2,024
Total liabilities associated with assets held for sale	$	1,329	$	3,573

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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 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 June 30, 2006, of which approximately $80 million and $240 million was incurred during the three and six month periods ended June 30, 2006, respectively, and was recognized in Loss From Discontinued Operations, net of tax. Management does not anticipate any additional material charges related to the DENA exit plan.

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 megawatts 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 are subject to LS Power obtaining certain state regulatory approvals. Subject to the resolution of these contingencies, an additional gain on the disposition of these assets could be recognized in a future period. 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. Upon successful completion of a 30 day appeals process LS Power, per the PSA, will make an additional payment to DENA of approximately $40 million. DENA will record this additional gain on sale of assets when received. This additional gain is expected to be received and recorded in Q3 2006.

As of June 30, 2006 and December 31, 2005, DENA’s assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets.

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 are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, DENA’s Southeastern generation operations, including related commodity contracts do not 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.

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 Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as certain CG&E trading contracts, to Fortis, a Benelux-based financial services group. Duke Energy will receive a base purchase price of approximately $210 million. In addition, Fortis will pay an amount equal to the value of the portfolio of contracts and net

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PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

working capital, including collateral, associated with the business, both of which will be determined at closing and are subject to market and operating changes up until that time. Duke Energy expects pre-tax cash proceeds from the sale to be at least $550 million, including the value of the portfolio of contracts and net working capital. The sale is subject to FERC and Federal Reserve Board approval, as well as Canadian regulatory approvals, and is anticipated to close in the third quarter of 2006. Results of operations for Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as certain CG&E trading contracts, have been reflected in Loss from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to June 30, 2006. Duke Energy does not currently expect a material gain or loss to be recognized in connection with this transaction. As of June 30, 2006, assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets.

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 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 Loss From Discontinued Operations, net of tax on the Consolidated Statements of Operations for the three months ended June 30, 2006. In July 2006, International Energy received the settlement proceeds.

14. Business Segments

In conjunction with the merger with Cinergy, effective with the second quarter ended June 30, 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 (pre-merger Duke Energy’s Franchised Electric segment regulated electric utility business in North Carolina and South Carolina) and legacy Cinergy regulated operations (consisting of the following Cinergy subsidiaries: CG&E’S regulated transmission and distribution, PSI and ULH&P

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

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

• Commercial Power—CG&E’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, CG&E and PSI, 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 one of Cinergy’s subsidiaries, CMT.

CG&E, 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 ULH&P, in nearby areas of Kentucky. CG&E’s 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.

PSI, 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,

27

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

“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).

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).

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.

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.

28

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 June 30, 2006
U.S Franchised Electric and Gas	$	2,125		$	5		$	2,130		$	351		$	358
Natural Gas Transmission		987			(8	)		979			361			119
Field Services(c)		—			—			—			148			—
Commercial Power		449			(2	)		447			20			55
International Energy		250			—			250			26			19
Crescent		85			—			85			174			—
Total reportable segments		3,896			(5	)		3,891			1,080			551
Other		77			48			125			(174	)		13
Eliminations		—			(43	)		(43	)		—			—
Interest expense		—			—			—			(339	)		—
Interest income and other(b)		—			—			—			43			—
Total consolidated	$	3,973		$	—		$	3,973		$	610		$	564
Three Months Ended June 30, 2005
U.S. Franchised Electric and Gas	$	1,229		$	5		$	1,234		$	274		$	240
Natural Gas Transmission		720			44			764			304			109
Field Services(c)		2,895			(23	)		2,872			164			71
Commercial Power		(2	)		38			36			(16	)		15
International Energy		182			—			182			86			16
Crescent		112			—			112			38			—
Total reportable segments		5,136			64			5,200			850			451
Other		138			7			145			(102	)		11
Eliminations		—			(71	)		(71	)		—			—
Interest expense		—			—			—			(295	)		—
Interest income and other(b)		—			—			—			32			—
Total consolidated	$	5,274		$	—		$	5,274		$	485		$	462
Six Months Ended June 30, 2006
U.S. Franchised Electric and Gas	$	3,413		$	9		$	3,422		$	710		$	590
Natural Gas Transmission		2,455			(2	)		2,453			799			241
Field Services(c)		—			—			—			292			—
Commercial Power		461			2			463			(7	)		69
International Energy		481			—			481			113			37
Crescent		156			—			156			216			—
Total reportable segments		6,966			9			6,975			2,123			937
Other		208			63			271			(232	)		23
Eliminations		—			(72	)		(72	)		—			—
Interest expense		—			—			—			(589	)		—
Interest income and other(b)		—			—			—			52			—
Total consolidated	$	7,174		$	—		$	7,174		$	1,354		$	960
Six Months Ended June 30, 2005
U.S. Franchised Electric and Gas	$	2,489		$	10		$	2,499		$	610		$	495
Natural Gas Transmission		1,875			80			1,955			715			223
Field Services(c)		5,470			60			5,530			1,083			143
Commercial Power		(3	)		52			49			(34	)		30
International Energy		350			—			350			154			31
Crescent		176			—			176			90			—
Total reportable segments		10,357			202			10,559			2,618			922
Other		245			(66	)		179			(286	)		21
Eliminations		—			(136	)		(136	)		—			—
Interest expense		—			—			—			(585	)		—
Interest income and other(b)		—			—			—			49			—
Total consolidated	$	10,602		$	—		$	10,602		$	1,796		$	943

(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 previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for the three and six months ended June 30, 2005 and as an equity method investment for the three and six months ended June 30, 2006.

29

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Segment assets in the following table exclude all intercompany assets.

Segment Assets

	June 30, 2006		December 31, 2005
	(in millions)
U.S. Franchised Electric and Gas(a)	$	29,408	$	18,739
Natural Gas Transmission		18,968		18,823
Field Services		1,444		1,377
Commercial Power(a)(b)		8,036		1,619
International Energy		3,297		2,962
Crescent		1,698		1,507
Unallocated Goodwill(d)		4,128		—
Total reportable segments		66,979		45,027
Other(b)		3,249		9,402
Reclassifications(c)		140		294
Total consolidated assets	$	70,368	$	54,723

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

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

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

(d) Unallocated Goodwill recorded as of June 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 at least half of the goodwill likely relating to the U.S. Franchised Electric and Gas segment.

15. Risk Management Instruments

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

Derivative Portfolio Carrying Value

	June 30, 2006			December 31, 2005
	(in millions)
Hedging	$	(23	)	$	(17	)
Trading		1			5
Undesignated		(98	)		(53	)
Total	$	(120	)	$	(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 $901 million of derivative assets and $770 million of derivative liabilities are presented as assets and liabilities held for sale at June 30, 2006.

The $45 million decrease in the undesignated derivative portfolio fair value is due primarily to termination of DENA’s sleeved transactions, primarily Barclay’s, partially offset by realized losses on certain contracts held by Duke Energy related to Field Services’ commodity price risk. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, 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 $250 million of pre-tax losses were recognized in earnings by Duke Energy as of June 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, while approximately $20 million and $130 million of pre-tax losses were recognized prior to the deconsolidation of DEFS as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues for the three and six months ended June 30, 2005, respectively. Approximately $21 million and $45 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy during the three and six months ended June 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 six months ended

30

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

June 30, 2006 of approximately $90 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 June 30, 2006 and December 31, 2005 are collateral assets of approximately $141 million and $1,279 million, respectively, excluding approximately $263 million which was reclassified to held for sale associated with the announced sale of Cinergy Marketing and Trading, LP. 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 June 30, 2006 and December 31, 2005 are collateral liabilities of approximately $294 million and $708 million, respectively, excluding approximately $15 million which was reclassified to held for sale primarily associated with the announced sale of Cinergy Marketing and Trading, LP. 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 June 30, 2006, $42 million of the 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 $10 million and an immaterial amount in the three and six months ended June 30, 2006, respectively, as compared to a pre-tax loss of approximately $11 million and $30 million in the three and six months ended June 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 June 30, 2006 and was a pre-tax loss of approximately $120 million as of June 30, 2005, and are reported in Loss From Discontinued Operations, net of tax and Impairments and Other Charges in the Consolidated Statements of Operations, respectively.

Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Energy actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in an immaterial amount and a pre-tax gain of $7 million in the three and six months ended June 30, 2006, respectively, as compared to immaterial amounts in the three and six months ended June 30, 2005, respectively.

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 customers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. Each of the commissions also required

31

32

Duke Energy Holding Corp., Cinergy, CG&E, ULH&P, and/or Duke Power Company LLC (Duke Power) 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:

• The PUCO’s conditions include a requirement that CG&E provide (i) a rate credit of approximately $15 million for one year to facilitate economic development in a time of increasing rates and (ii) a credit of approximately $21 million to CG&E’s gas and electric customers 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 committed reversible error on both procedural and substantive grounds by, among other things, failing to set the matter for a full evidentiary hearing, failing to consider evidence regarding the transfer of certain DENA assets to CG&E, and failing to lift the stay on discovery. CG&E and the OCC have resolved this matter through settlement and in May 2006, the OCC filed a motion to dismiss. In June 2006, the court granted the motion to dismiss. As of June 30, 2006, CG&E has returned $7 million and $9 million, respectively, on each of these rate credits

• The KPSC’s conditions include a requirement that ULH&P provide $7.6 million in rate credits to ULH&P customers over five years, ending when new rates are established in the next rate case after January 1, 2008. As of June 30, 2006, ULH&P has returned $1 million to customers on this rate credit.

• The PSCSC’s conditions include a requirement that Duke Power provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing profit sharing arrangement. Approximately $3 million of the rate reduction have been passed through to customers since the ruling by the PSCSC.

• The NCUC’s conditions include a requirement that Duke Power provide (i) a rate reduction of approximately $117.5 million for Duke Power’s 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.

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 Power is required to file a general rate case or demonstrate that Duke Power’s 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 Power are in fact unjust or unreasonable.

• The IURCs conditions include a requirement that PSI provide a rate credit of $40 million to PSI customers over a one year period and $5 million 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 PSI should be ordered to provide an additional $5 million in rate credits 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 June 30, 2006, PSI has returned $3 million to customers on this rate credit.

• The FERC approved the merger without conditions. On January 19, 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. On February 21, 2006, the FERC issued an order granting rehearing of FERC’s order for further consideration. A decision by FERC is expected in the third quarter of 2006.

U.S. Franchised Electric and Gas. Rate Related Information. The NCUC, PSCSC, PUCO, IURC and KPSC approve rates for retail electric and gas sales within their states. The FERC approves rates for electric sales to regulated wholesale customers.

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 Power, 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 Power, 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

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estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). Duke Powers’ amortization expense related to this clean air legislation totals approximately $763 million from inception, with approximately $63 million and $71 million recorded in the second quarter of 2006 and 2005, respectively, and approximately $125 million and $156 million recorded for the first six months of 2006 and 2005, respectively. As of June 30, 2006, cumulative expenditures totaled $599 million, with $174 million incurred for the first six months of 2006 and $134 million incurred for the first six months of 2005 and are included in Net Cash Provided by Investing Activities on the Consolidated Statements of Cash Flows. In recent filings with the NCUC, Duke Energy Carolinas has estimated the costs to comply with the legislations 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.

PSI Environmental Compliance Case. In November 2004, PSI applied to the IURC for approval of its plan for complying with sulfur dioxide (SO₂ ), nitrogen oxides (NO_X), and mercury emission reduction requirements. PSI also requested approval of cost recovery for certain proposed compliance projects. An evidentiary hearing was held in May 2005. In December 2005, PSI, the Indiana Office of Utility Consumer Counselor (OUCC), and the PSI Industrial Group filed a settlement agreement providing for approval of PSI’s compliance plan, and approval of financing, depreciation, and operation and maintenance 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 costs, and (6) authority to defer post-in-service AFUDC, depreciation costs and operation and maintenance cost until applicable costs are reflected in rates.

CG&E Electric Rate Filings. CG&E operates under a Market Based Standard Service Order (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. CG&E’s MBSSO does not contain a competitive bid process pursuant to a statutory exception. CG&E 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 CG&E expect the court to decide the case in 2006. On August 2, 2006, CG&E filed an application with the PUCO to extend CG&E’s MBSSO. The proposal provides for continued electric system reliability, a simplified rate structure and clear price signals for customers, while helping to maintain a stable revenue stream for CG&E. The application also proposes that the PUCO review and approve the application by the end of 2006.

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

CG&E filed a distribution rate case to recover certain distribution costs with rates becoming effective on January 1, 2006 and CG&E has deferred certain costs 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.

ULH&P Electric Rate Case. In May 2006, ULH&P filed an application for an increase in its base electric rates. The application, which seeks an increase of approximately $65 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 CG&E to ULH&P. ULH&P is also seeking to reinstitute its fuel cost recovery mechanism which has been frozen since 2001, and has proposed to refresh the pricing for the back-up supply contract to reflect current market pricing. After ULH&P supplemented its filing in June 2006, the KPSC issued an order in

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June 2006, shortening the notice period for new rates from 30 to 20 days and suspending rates for six months, until January 6, 2007. At this time, Duke Energy and ULH&P cannot predict the outcome of this proceeding.

ULH&P Gas Rate Case. In 2002, the KPSC approved ULH&P’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 such costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism. In 2005, both ULH&P and the KPSC requested that the court dismiss the case. At the present time, Duke Energy and ULH&P cannot predict the timing or outcome of this litigation.

In February 2005, ULH&P 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 including recovery of the current cost of the accelerated main replacement program in base rates. The KPSC did not rule on the base rate case request or the request to continue the tracking mechanism by October 1, 2005; consequently the initial tracking mechanism expired on September 30, 2005. In accordance with Kentucky law, ULH&P implemented the full amount of the requested rate increase on October 1, 2005. In December 2005, the KPSC approved an annual rate increase of $8.1 million and re-approved the tracking mechanism through 2011. Pursuant to the KPSC’s order, ULH&P filed a refund plan in January 2006 for the excess revenues collected since October 1, 2005. In February 2006, the KPSC issued an additional order responding to a rehearing request made by the Attorney General. Its rehearing order approved ULH&P’s refund plan, which resulted in refunds being provided to customers beginning in March 2006. In February 2006, the Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows ULH&P to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows ULH&P to earn a return on investment for the costs recovered under the tracking mechanism which permits ULH&P to recover its gas main replacement costs. At this time, Duke Energy and ULH&P cannot predict the outcome of this litigation.

Bulk Power Marketing (BPM) Profit Sharing. The NCUC approved Duke Power’s 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 Power’s generating units at market based rates (BPM Profits). Duke Power 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 with the Carolina Utility Customers Association (CUCA) and the North Carolina Public Staff on Duke Power’s method for determining the incremental costs of emission allowances used to calculate the BPM Profits for sharing. The NCUC agreed with the Public Staff’s method and ordered Duke Power to file a revised rate rider on June 29, 2006 and to implement the new rider effective July 1, 2006. The Public Staff’s method results in higher BPM Profits to be shared for the period beginning with January 1, 2005. It also is not the method contemplated by Duke Power when it initiated the sharing program and it results in a greater sharing of the profits earned in the January 2005 to December 2005 sharing period than proposed by Duke Power when the program was first approved. This resulted in an $18 million charge during the six months ended June 30, 2006, of which $11 million related to wholesale sales in 2005. On June 29, 2006, Duke Power filed a motion to postpone the effective date of the NCUC’s order to allow time for Duke Power to consider its options and to in any event gather the necessary data to employ the Public Staff’s method and to implement a revised rider. The NCUC approved Duke Power’s request on June 30. On July 17, 2006, Duke Power filed another motion requesting that the NCUC reconsider its June 28 order. In the alternative, Duke Power requested that the NCUC make its order effective only prospectively with respect to sharing periods beginning January 1, 2007. Duke Power also requested that if the NCUC was not inclined to grant its request to reinstate its proposed rider, then the NCUC should approve Duke Power’s withdrawal of the rider at its option. Duke Power’s request is scheduled for oral arguments on August 29, 2006.

Duke Power’s 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 Power. The approved factor is a 13% increase from the previously approved net fuel factor of 1.4769 cents/kWh. In approving the fuel factor, the NCUC rejected CUCA’s request for a disallowance of approximately $50

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million because of an alleged failure by Duke Power to diversify the type of coal it burns. An application for a revised fuel factor that will be effective October 2006 to September 2007 in South Carolina was filed on July 27, 2006. A hearing on the application is scheduled for August 2006.

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 Power 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 Power 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 megawatts. 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. Duke Power will decide whether to proceed with construction at a later date.

On June 2, 2006, Duke Power 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. On July 6, 2006, the NCUC issued its scheduling order in this case. It will hold public hearings in August 2006, and an evidentiary hearing in Raleigh, North Carolina in September 2006. Interventions are due in August 2006.

In May 2006, Duke Power 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 Westinghouse 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 over the next twenty years. The transaction, which is anticipated to close in the fourth quarter of 2006, requires approvals by the NCUC and FERC. In addition, approval is 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 is pending.

PSI 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). PSI and Vectren reached a Settlement Agreement with the Indiana Office of Utility Consumer Counselor 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.

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.

Union Gas has rates that are approved by the 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 result of the agreement is an average rate increase of approximately 2.7% effective January 1, 2007. 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. 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

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

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina, and its three natural gas-fired generating facilities in California are affected sources under the rule. The three California facilities are part of the DENA business and were sold as part of the transaction announced in January 2006 that closed in May 2006 (see Note 13). 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 final 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 the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAMR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAMR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAMR.

Clean Air Interstate Rule. The EPA finalized its Clean Air Interstate Rule (CAIR) in [May] 2005. The rule limits total annual SO₂ and NOx emissions from electric generating facilities across the Eastern United States through a two-phased cap-and-trade program. Phase 1

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begins in 2009 for NOx and in 2010 for SO₂. Phase 2 begins in 2015 for both NOx and SO₂. The rule requires 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 trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls that Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAIR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAIR. On July 11, 2005, Duke Energy and others filed petitions with the U.S. Court of Appeals for the District of Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy is seeking to have the EPA revise the method of allocating SO₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $70 million and $55 million as of June 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.

Litigation

New Source Review (NSR)/EPA Litigation. In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a complaint against Duke Energy in the U.S. District Court in Greensboro, North Carolina, for alleged violations of the Clean Air Act (CAA). The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units were major modifications, as defined in the CAA, and that Duke Energy violated the CAA when it undertook those projects without obtaining permits and installing emission controls for SO₂, NOx and particulate matter. The complaint asks the Court to order Duke Energy to stop operating the coal-fired units identified in the complaint, install additional emission controls and pay unspecified civil penalties. Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy’s legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy. The government appealed the case to the U.S. Fourth Circuit Court of Appeals. On June 15, 2005, the Fourth Circuit ruled in favor of Duke Energy and effectively adopted Duke Energy’s view that permitting of projects is not required unless the work performed implicates a net increase in the hourly rate of emissions. The EPA filed a request for rehearing with the Fourth Circuit, which was denied. The EPA decided not to petition the U.S. Supreme Court to hear an appeal of the matter. Some environmental groups who intervened in the early stages in the case have filed their petition for appeal. The Supreme Court has elected to hear this matter and oral argument is expected to be scheduled in the fourth quarter of 2006.

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, CG&E, and PSI 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 CG&E’s W.C. Beckjord Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’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, CG&E, and PSI at the trial of the case. Contrary to Cinergy’s, CG&E’s, and PSI’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, which has accepted the appeal. Oral arguments were held before the Seventh Circuit Court of Appeals in June 2006. In February 2006, the district court ruled that in carrying its burden of proof, the defendant can look to industry practice in proving a particular project was routine. The district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. Notwithstanding the appeal, there are a number of other legal issues currently before the district court judge.

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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 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 CG&E. 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 CG&E 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 CG&E. 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 CG&E, 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 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 CO₂ emissions 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. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of 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 will require regulatory approval. Based on the terms of the Settlement Agreement and Mutual Release, Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

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

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Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants, and on September 30, 2005, the court 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 who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

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 class action petition was filed in state court in Kansas and on May 19, 2006 another class action petition was filed in Colorado state court. These cases were also filed against Duke Energy and DETM, as well as other energy companies. Each of these cases contains similar claims, that the respective plaintiffs 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 states. Plaintiffs seek damages in unspecified amounts. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

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

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 $187 million. The Court has made rulings regarding the issues of fact and law that remain for trial, and the parties have jointly requested a trial setting in December 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.

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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, 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 not specified in the arbitration demand. 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. In response to a request from Exxon Mobil, the arbitration panel has postponed the commencement date of the arbitration hearing from January 2006 to October 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain 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 supply agreements. If DEMLP and ExxonMobil cannot agree on the damages to be paid as the result of the first ruling, the issue will be decided by 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 adjustment 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 Power Company Employees’ Retirement Plan into the Duke Power Company 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 Duke defendants’, greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. Neither Duke Energy nor Cinergy has been 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 Power Company LLC on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party

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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.

PSI and CG&E 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 PSI cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors in the construction and maintenance of PSI and CG&E generating stations. The plaintiffs further claim that as the property owner of the generating stations, PSI and CG&E 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 or results of operations of these cases to date has not been material.

Of these lawsuits, one case filed against PSI has been tried to verdict. The jury returned a verdict against PSI on a negligence claim and a verdict for PSI on punitive damages. PSI appealed this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. PSI paid the judgment of approximately $630,000 in the fourth quarter of 2005. In addition, PSI has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to PSI’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 PSI 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.

CG&E 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. Cinergy produces synthetic fuel from two facilities that qualify 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 June 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. Oil prices are currently at a level where Duke Energy has idled the plants, as the value of the credits may not exceed the net costs to produce the synthetic fuel. 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 quarter. Duke Energy’s net investment in the plants at June 30, 2006 was approximately $24 million. Based upon the increase in crude oil prices subsequent to June 30, 2006, it is possible that Duke Energy may incur a future impairment of its net investment in the synthetic fuel plants.

The Internal Revenue Service (IRS) has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years including the synfuel 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.

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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 June 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 June 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

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. 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 Capital 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 June 30, 2006 was approximately $637 million. Of this amount, approximately $408 million relates to guarantees of the payment and performance of less than wholly-owned consolidated entities. Approximately $332 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

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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 entities. The maximum potential amount of future payments Cinergy Corporation could have been required to make under these performance guarantees as of June 30, 2006 was approximately $113 million. All of the performance guarantees expire after 2007 or have no contractual expiration.

Westcoast Energy, Inc. (Westcoast) has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of June 30, 2006 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly-owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of June 30, 2006 was approximately $25 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, 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 June 30, 2006, Duke Capital had guaranteed approximately $15 million of outstanding surety bonds related to obligations of non-wholly-owned entities. The majority of these bonds expire in various amounts in 2006.

In 1999, IDC issued approximately $100 million in bonds to purchase equipment for lease to 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 June 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 June 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of June 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, International Energy, and Crescent have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission, International Energy, or Crescent would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of June 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. Crescent was the guarantor of approximately $15 million of debt associated with less than wholly-owned entities, which expire in 2006.

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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 June 30, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

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 business to Duke Energy shareholders. The new gas company, which has yet to be named, 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 Crescent Resources. Duke Energy is targeting a January 1, 2007 effective date for the transaction. At June 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 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.

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 six months ended June 30, 2006 was approximately $149 million and $295 million, respectively, and Duke Energy’s investment in DEFS as of June 30, 2006 was $1,371 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. During the three months ended June 30, 2006, Duke Energy had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $35 million, $23 million and $7 million, respectively. During the six months ended June 30, 2006, Duke Energy had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $69 million, $31 million and $15 million, respectively. As of June 30, 2006, Duke Energy had payables to affiliates of DEFS of approximately $50 million. Additionally, Duke Energy received approximately $230 million in distributions of earnings from DEFS in 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 $77 million receivable as of June 30, 2006 due to its share of a distribution declared by DEFS in June 2006 but paid in July 2006. Summary financial information for DEFS, which is accounted for under the equity method, as of and for the three and six months ended June 30, 2006 is as follows:

	Three months Ended June 30, 2006		Six months Ended June 30, 2006
	(in millions)		(in millions)
Operating revenues	$	3,002	$	6,311
Operating expenses	$	2,657	$	5,651
Operating income	$	345	$	660
Net income	$	299	$	590

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	June 30, 2006
	(in millions)
Current assets	$	2,055
Non-current assets	$	4,838
Current liabilities	$	2,098
Non-current liabilities	$	2,040
Minority interest	$	93

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.

Duke Energy has entered into an agreement to sell 100% of the shares of Westcoast Gas Services, Inc. (WGSI), which owns interests in four gas processing plants and related gas gathering systems, to the Duke Energy Income Fund (Income Fund) for approximately $128 million. The Income Fund is a Canadian income trust that was created in December 2005, and the sale of WGSI reduced Duke Energy’s ownership interest in the Income Fund from approximately 58% to approximately 46%. Closing of the sale is conditional upon approval by the fund unitholders, other than Duke Energy, and its affiliates and is expected to occur during the third quarter of 2006.

Also see Notes 2, 12, 13 and 18 for additional related party information.

20. New Accounting Standards

The following new accounting standards were adopted by Duke Energy subsequent to June 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. 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.

FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations” (FIN 47). In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for Duke Energy as of December 31, 2005.

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 of 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18, “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

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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.

SFAS No. 123(R). “Share-Based Payment.” In December of 2004, the FASB issued SFAS No. 123(R), which replaces SFAS No. 123 and supersedes APB Opinion No. 25. 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 will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

SFAS No. 123(R), which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a material impact on its 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).

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.” In February 2006, the FASB staff issued FSP 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 FAS No. 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 FAS No. 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP FAS No. 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 FAS No. FAS 123(R)-4 did not have a material impact on Duke Energy’s consolidated statement of operations, cash flows or financial position.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB 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 107 effective January 1, 2006.

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.” 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 Equity Method of Accounting for Investments in Common Stock.” 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.

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Notes To Consolidated Financial Statements—(Continued)

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

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140”. 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. This Statement 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”. 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. This Statement 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.

FASB Staff Position (FSP) No. FIN 46 (R)-6, “Determining the Variability to Be Considered In Applying FASB Interpretation No. 46(R).” 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 FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities.” The variability that is considered in applying Interpretation 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 will be applied prospectively to all entities with which Duke Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. Duke Energy does not anticipate the adoption of FSP No. FIN 46 (R)-6 will have any material impact on its 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 05-1). In June 2006, the EITF reached a consensus on Issue 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 securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus is effective for Duke Energy for all conversions within its scope that result from the exercise of call options beginning July 1, 2006. Duke Energy does not anticipate the adoption of EITF Issue 05-1 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 06-3). In June 2006, the EITF reached a consensus on Issue 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., include 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 Issue 06-3 will have any material impact on its consolidated results of operations.

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Notes To Consolidated Financial Statements—(Continued)

FASB Interpretation 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 fiscal years beginning after December 15, 2006. 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.

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 June 30, 2006, Duke Energy has total provisions of approximately $215 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. 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 June 30, 2006 was approximately 28.7% as compared to the effective tax rate of 32.4% for the same period in 2005. The effective tax rate for the six months ended June 30, 2006 was approximately 32.0% as compared to the effective tax rate of 33.9% for the same period in 2005. The decrease in the effective tax rates for both periods was primarily attributable to reductions in state deferred tax liabilities related to the merger with Cinergy.

22. Subsequent Events

For information on subsequent events related to acquisitions and dispositions, debt and credit facilities, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies and related party transactions, see Notes 2, 7, 13, 16, 17 and 19, respectively.

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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. 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 six months ended June 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.

On April 3, 2006, Duke Energy and Cinergy consummated the previously announced merger, which combines 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 requires various approvals and is anticipated to close by year-end 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 Transmission business segment to Duke Energy shareholders. The new natural gas company, which has yet to be named, 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 decision to spin off the natural gas business is expected to deliver long-term value to shareholders as the stand-alone companies will be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations. Approximately $3 billion of debt currently at Duke Capital LLC (Duke Capital) is anticipated to transfer to the new natural gas company at the time of the spin-off. Duke Energy is targeting a January 1, 2007 effective date for the transaction and the results of the natural gas business are expected to be treated as discontinued operations in the period the spin-off is consummated.

The businesses remaining in Duke Energy post-spin are anticipated to be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Crescent Resources, LLC (Crescent).

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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 Duke Energy North America (DENA) power generation fleet outside of the Midwest to LS Power Equity Partners (LS Power) and has agreed to sell the Cinergy commercial marketing and trading business to Fortis, a Benelux-based financial services group (Fortis). The sale to Fortis is subject to various approvals and is anticipated to close in the third quarter of 2006.

Additionally, the Board of Directors of Duke Energy has 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.

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.

For the three months ended June 30, 2006, Duke Energy reported net income of $355 million and diluted earnings per share of $0.28 as compared to net income and diluted earnings per share of $309 million and $0.32, respectively, for the three months ended June 30, 2005. The decrease in earnings per share was due primarily to the increase in number of shares outstanding, primarily as a result of the issuance of shares in connection with the Cinergy merger and conversions of debt to equity, offset by the repurchase of shares under the share repurchase program, during the second quarter of 2006 (see Note 2 to the Consolidated Financial Statements, “Earnings Per Share”). These results include the impacts of former Cinergy for the quarter ended June 30, 2006. For the six months ended June 30, 2006, Duke Energy reported net income of $713 million and diluted earnings per share of $0.64 as compared to net income and diluted earnings per share of $1,177 million and $1.20, respectively, for the six months ended June 30, 2005. These amounts include the results of former Cinergy for the quarter ended June 30, 2006. The decrease in net income and earnings per share was due primarily to the pre-tax gain 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 (TEPPCO LP), and Duke Energy’s sale of its limited partner interests in TEPPCO LP and the recognition of prior year hedge losses. In addition to the impact of lower net income for the first six months of 2006 as compared to the same period in 2005, the decrease in earnings per share for this period was partially attributable to the increase in number of shares outstanding, as discussed above. The highlights for the three and six months ended June 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 six months ended June 30, 2006 as compared to the same periods in the prior year, primarily due to the inclusion of legacy Cinergy for the second quarter ended June 30, 2006, improved weather in the Duke Energy Carolinas region and customer growth in the service territories, partially offset by lower wholesale power revenues, rate credits and contributions as a result of stipulations to merger approval and an approximate $18 million charge related to a North Carolina Utility Commission (NCUC) order that changed the methodology for calculating BPM profit sharing;

• Natural Gas Transmission’s earnings increased over the same periods in the previous year due to higher natural gas processing—primarily from the addition of the Empress assets acquired in 2005, business expansion, favorable resolution of property tax issues and the impact of a strengthening Canadian currency. These results were partially offset by higher operating costs and lower equity earnings related to interest expense;

• Field Services results 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 reduction in ownership percentage by Duke Energy as a result of the DEFS disposition transaction whereby Duke Energy reduced its ownership interest in DEFS from 69.7% to 50% effective July 1, 2005, 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 non-regulated generation and marketing in the Midwest and Duke Energy Generation Services, including DENA’s Midwest power generating assets, reported improved results 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. Results were partially offset by approximately $48 million in purchase accounting adjustments recorded during second quarter 2006, a lack of tax credits associated with Cinergy’s synfuel facilities and operating costs associated with Cinergy’s synfuel facilities;

• International Energy experienced lower earnings compared to the same periods in the prior year primarily driven by an impairment of the Campeche equity investment in Mexico and related note receivable reserve, increased power purchases as a result of an

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unplanned outage in Peru and unfavorable hydrology in Peru and Brazil. These results were partially offset by favorable currency impacts—mainly in Brazil;

• Crescent had improved results compared to same periods in the prior year, driven primarily by an approximate $81 million gain on the sale of properties at Potomac Yard in Washington, DC, and an approximate $52 million land sale at Lake Keowee in South Carolina during 2006;

• Other losses increased for the three months ended June 30, 2006 compared to the same period in the prior year due primarily to charges in 2006 associated with the Cinergy merger, partially offset by a reduction in charges for liabilities associated with mutual insurance companies. For the six months ended June 30, 2006, Other losses decreased for the six months ended June 30, 2006 compared to the same period in the prior year primarily as a result of a reduction in charges for liabilities associated with mutual insurance companies and lower losses on Field Services hedges, partially offset by Cinergy merger related costs; and

• Loss from discontinued operations, primarily related to the exit of the DENA business, increased in 2006 compared to the same periods in the prior year due primarily to the 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 June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	3,973		$	5,274		$	(1,301	)	$	7,174		$	10,602		$	(3,428	)
Operating expenses		3,363			4,508			(1,145	)		5,801			9,170			(3,369	)
Gains on sales of investments in commercial and multi-family real estate		145			12			133			171			54			117
(Losses) gains on sales of other assets and other, net		(11	)		—			(11	)		22			9			13
Operating income		744			778			(34	)		1,566			1,495			71
Other income and expenses, net		220			80			140			407			1,384			(977	)
Interest expense		339			295			44			589			585			4
Minority interest expense		15			78			(63	)		30			498			(468	)
Earnings from continuing operations before income taxes		610			485			125			1,354			1,796			(442	)
Income tax expense from continuing operations		175			157			18			433			608			(175	)
Income from continuing operations		435			328			107			921			1,188			(267	)
Loss from discontinued operations, net of tax		(80	)		(19	)		(61	)		(208	)		(11	)		(197	)
Net income		355			309			46			713			1,177			(464	)
Dividends and premiums on redemption of preferred and preference stock		—			2			(2	)		—			4			(4	)
Earnings available for common stockholders	$	355		$	307		$	48		$	713		$	1,173		$	(460	)

Consolidated Operating Revenues

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating revenues for the three months ended June 30, 2006 decreased $1,301 million, compared to the same period in 2005. This change was driven primarily by:

• A $2,872 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in revenues were:

• An approximate $1,266 million increase due to the merger with Cinergy

• A $215 million increase at Natural Gas Transmission due to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $122 million), favorable Canadian dollar foreign exchange impacts (approximately $47 million),

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recovery of higher natural gas commodity costs (approximately $27 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas Limited (Union Gas), partially offset by lower gas usage due to unseasonably warmer weather (approximately $19 million), and

• A $68 million increase at International Energy due to increased ownership and resulting consolidation of Aguaytia (approximately $28 million), higher energy prices and generation in Latin America (approximately $25 million) and an increase in Brazil mainly due to favorable exchange rates and higher average prices (approximately $11 million).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating revenues for the six months ended June 30, 2006 decreased $3,428 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

Partially offsetting this decrease in revenues were:

• An approximate $1,266 million increase due to the merger with Cinergy

• A $498 million increase at Natural Gas Transmission due to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $267 million), recovery of higher natural gas commodity costs (approximately $145 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 $102 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $104 million)

• A $131 million increase at International Energy due to higher energy prices and favorable exchange rates in Latin America (approximately $79 million) and increased ownership and resulting consolidation of Aguaytia (approximately $48 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 June 30, 2006 as Compared to June 30, 2005. Consolidated operating expenses for the three months ended June 30, 2006 decreased $1,145 million, compared to the same period in 2005. This change was driven primarily by:

• A $2,636 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in expenses were:

• An approximate $1,152 million increase due to the merger with Cinergy

• A $152 million increase at Natural Gas Transmission due to new Canadian assets, primarily the Empress System (approximately $91 million), Canadian dollar foreign exchange impacts (approximately $37 million) and increased natural gas prices at Union Gas (approximately $27 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $15 million), and

• A $106 million increase at International Energy primarily due to a reserve on a note receivable from the Campeche equity investment (approximately $38 million) (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”), increased ownership and resulting consolidation of Aguaytia (approximately $31 million), and higher fuel prices and volumes in Latin America due to increased generation (approximately $17 million).

• A $74 million increase associated with costs to achieve the Cinergy merger.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating expenses for the six months ended June 30, 2006 decreased $3,369 million, compared to the same period in 2005. This change was driven primarily by:

• A $5,207 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in expenses were:

• An approximate $1,152 million increase due to the merger with Cinergy

• A $431 million increase at Natural Gas Transmission due to new Canadian assets, primarily the Empress System (approximately $222 million), increased natural gas prices at Union Gas (approximately $145 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, Canadian dollar foreign exchange impacts (approximately $81 million), partially offset by lower gas purchase costs due to unseasonably warmer weather (approximately $82 million), and

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• A $144 million increase at International Energy primarily due to increased ownership and resulting consolidation of Aguaytia (approximately $44 million), a reserve on a note receivable from the Campeche equity investment (approximately $38 million), and higher fuel prices and volumes in Latin America due to increased generation (approximately $35 million).

• A $78 million increased associated with costs to achieve the Cinergy merger.

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

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

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated gains on sales of investments in commercial and multi-family real estate increased $133 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.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated gains on sales of investments in commercial and multi-family real estate increased $117 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.

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

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated (losses) gains on sales of other assets and other, net for the six months ended June 30, 2006 increased $13 million, compared to the same period in 2005. The increase was due primarily to an approximate $23 million gain on the settlement of a customer’s transportation contract at Natural Gas Transmission in 2006, partially offset by an approximate $5 million loss on a contract termination.

Consolidated Operating Income

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating income for the three months ended June 30, 2006 decreased $34 million, compared to the same period in 2005. Decreased operating income was primarily related to impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to $235 million for the three months ended June 30, 2005, partially offset by approximately $100 million of operating income in the three months ended June 30, 2006 generated by legacy Cinergy as a result of the merger. Other drivers to operating income are discussed above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating income for the six months ended June 30, 2006 increased $71 million, compared to the same period in 2005. Increased operating income was primarily related to approximately $100 million of operating income generated by legacy Cinergy as a result of the merger and an approximate $250 million negative impact to operating income during the six months ended June 30, 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. Partially offsetting those results were the impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to $322 million for the six months ended June 30, 2005. Other drivers to operating income are discussed above.

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

Consolidated Other Income and Expenses, net

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated other income and expenses, net for the three months ended June 30, 2006 increased $140 million, compared to the same period in 2005. The increase was due primarily to an increase of approximately $155 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005, partially offset by approximately $20 million of impairment charges on equity method investments recorded in the second quarter 2006, primarily International Energy’s investment in Campeche (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated other income and expenses, net for the six months ended June 30, 2006 decreased $977 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 $289 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005.

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Consolidated Interest Expense

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated interest expense for the three months ended June 30, 2006 increased $44 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 the deconsolidation of DEFS.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated interest expense for the six months ended June 30, 2006 remained relatively flat, increasing $4 million, compared to the same period in 2005. Although consolidated interest expense remained relatively flat, interest expense in 2006 was impacted by the increase in long-term debt as a result of the merger with Cinergy, which was offset by reduced interest expense associated with DEFS, which was deconsolidated on July 1, 2005. Interest expense in 2005 reflected amounts related to debt associated with DEFS prior to the deconsolidation on July 1, 2005.

Consolidated Minority Interest Expense

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated minority interest expense for the three months ended June 30, 2006 decreased $63 million, compared to the same period in 2005. The decrease primarily resulted from the impact of deconsolidation of DEFS, as discussed above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated minority interest expense for the six months ended June 30, 2006 decreased $468 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, as discussed above.

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated income tax expense from continuing operations for the three months ended June 30, 2006 increased $18 million, compared to the same period in 2005. The increase primarily resulted from higher pre-tax earnings. The effective tax rate decreased in the three months ended June 30, 2006 (28.7%) compared to the same period in 2005 (32.4%), primarily due to reductions in state deferred tax liabilities related to the merger with Cinergy.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated income tax expense from continuing operations for the six months ended June 30, 2006 decreased $175 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. The effective tax rate decreased in the six months ended June 30, 2006 (32.0%) compared to the same period in 2005 (33.9%), primarily due to reductions in state deferred tax liabilities related to the merger with Cinergy.

Consolidated Loss from Discontinued Operations, net of tax

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated loss from discontinued operations, net of tax for the three months ended June 30, 2006 increased $61 million, compared to the same period in 2005. This increase primarily resulted from an approximate $61 million increase in after-tax loss at DENA associated with certain contract terminations or sales, an approximate $6 million after-tax loss associated with the exiting of the Cinergy commercial marketing and trading operations, partially offset by an approximate $5 million increase in after-tax gain at International Energy due primarily to a write-up of a receivable from Norsk Hydro (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated loss from discontinued operations, net of tax for the six months ended June 30, 2006 increased $197 million, compared to the same period in 2005. This increase primarily resulted from an approximate $184 million increase in after-tax loss at DENA associated with certain contract terminations or sales, an approximate $6 million after-tax loss associated with exiting the Cinergy commercial marketing and trading operations and an approximate $13 million increase in after-tax loss at International Energy primarily as a result of the recording of an allowance against a receivable, offset by the $5 million after-tax write-up as mentioned 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

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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.

EBIT by Business Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
U.S. Franchised Electric and Gas	$	351		$	274		$	710		$	610
Natural Gas Transmission		361			304			799			715
Field Services(a)		148			164			292			1,083
Commercial Power		20			(16	)		(7	)		(34	)
International Energy		26			86			113			154
Crescent		174			38			216			90
Total reportable segment EBIT		1,080			850			2,123			2,618
Other		(174	)		(102	)		(232	)		(286	)
Total reportable segment and other EBIT		906			748			1,891			2,332
Interest expense		(339	)		(295	)		(589	)		(585	)
Interest income and other(b)		43			32			52			49
Consolidated earnings from continuing operations before income taxes	$	610		$	485		$	1,354		$	1,796

(a) In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for the three and six month periods ended June 30, 2005 and as an equity method investment for the three and six months ended June 30, 2006.

(b) Includes interest income, foreign currency transaction gains and losses, additional minority interest expense not allocated to the segment results and intersegment eliminations.

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

US Franchised Electric and Gas

	Three Months Ended June 30,								Six Months Ended June 30,
	2006		2005			Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,130	$	1,234		$	896		$	3,422	$	2,499	$	923
Operating expenses		1,791		959			832			2,729		1,890		839
Gains on sales of other assets and other, net		2		—			2			2		1		1
Operating income		341		275			66			695		610		85
Other income and expenses, net		10		(1	)		11			15		—		15
EBIT	$	351	$	274		$	77		$	710	$	610	$	100
Duke Energy Carolinas GWh sales(a)		19,944		20,431			(487	)		40,524		41,594		(1,070	)
Duke Energy Midwest GWh sales(a)(b)		14,803		—			14,803			14,803		—		14,803

(a) Gigawatt-hours (GWh)

(b) Relates to operations of former Cinergy

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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		Six Months Ended
Residential sales(a)	4.5	%	(0.7	)%
General service sales(a)	4.1	%	1.5	%
Industrial sales(a)	(0.8	)%	(2.1	)%
Wholesale sales	(50.7	)%	(28.4	)%
Total DE Carolinas sales(b)	(2.4	)%	(2.6	)%
Average number of customers	2.1	%	1.9	%

(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 June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

• A $848 million increase in regulated operating revenues due to the merger with Cinergy

• A $52 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 4%, resulting in more fuel revenue collections from those customers. The delivered cost of coal in 2006 is approximately $7 per ton higher than the same period in 2005, representing a 12% increase

• A $29 million increase related to GWh sales to retail customers due to more favorable weather conditions during the quarter than compared to the same period in 2005. Weather statistics for cooling degree days were approximately 1% below normal in second quarter 2006 compared to 24% below normal during the same period in 2005, partially offset by

• A $37 million decrease in wholesale power revenues. While prices were favorable, sales volumes decreased by approximately 51% partly due to production constraints caused by generation outages. In addition to lower wholesale sales volumes, the lower results reflected an $18 million charge due to an order issued by the NCUC in 2006 to change the method for calculating wholesale profits and related sharing. This order was retroactive to January 1, 2005, and, therefore, $11 million of the recorded charge related to wholesale sales in 2005.

Operating Expenses. The increase was driven primarily by:

• A $786 million increase in regulated operating expenses due to the merger with Cinergy

• A $48 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 second quarter for both 2006 and 2005 and the delivered cost of coal is approximately $7 per ton higher than the same period in 2005, and

• A $9 million increase in donations, primarily due to a one time $12 million donation, ordered by the NCUC as a condition of the Cinergy merger, to help support various low income, environmental, economic development and educationally beneficial programs in North Carolina.

Other Income and expenses, net. The increase was driven primarily by the addition of Cinergy and a $6 million increase in the allowance for funds used during construction (AFUDC), due primarily to on-going construction projects in the Carolinas.

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy and more favorable weather conditions in the Carolinas in comparison to the same period in 2005. These changes were partially offset by decreased Carolinas’ sales to wholesale customers due to limited market opportunities and the NCUC order changing the calculation of wholesale profits.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

• A $848 million increase in regulated operating revenues due to the merger with Cinergy

• A $77 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 $9 per ton higher than the same period in 2005, representing a 15% increase

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• An $18 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 43,000 compared to the same period in 2005, partially offset by

• A $25 million decrease in wholesale power revenues. While prices were favorable, sales volumes decreased by approximately 30% partly due to production constraints caused by generation outages. In addition to lower wholesale sales volumes, the lower results reflected an $18 million charge due to an order issued by the NCUC in 2006 to change the method for calculating wholesale profits and related sharing. This order was retroactive to January 1, 2005, and, therefore, $11 million of the recorded charge related to wholesale sales in 2005. For the six months ended June 30, 2006, the sharing of profits was $31 million while for the same period in 2005, the sharing of profits was $22 million.

Operating Expenses. The increase was driven primarily by:

• A $786 million increase in regulated operating expenses due to the merger with Cinergy

• An $80 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 second quarter for both 2006 and 2005 and the delivered cost of coal is approximately $9 per ton higher than the same period in 2005

• A $9 million increase in donations, primarily due to a one time $12 million donation, ordered by the NCUC as a condition of the Cinergy merger, to help support various low income, environmental, economic development and educationally beneficial programs in North Carolina, partially offset by

• A $31 million decrease in Duke Energy Carolinas regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005.

Other Income and expenses, net. The increase was driven primarily by an $11 million increase in AFUDC, due primarily to on-going construction projects in the Carolinas and the acquisition of Cinergy.

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, increased demand by Carolina retail customers and reduced regulatory amortization in the Carolinas. This increase was partially offset by lower wholesale power sales in the Carolinas.

Natural Gas Transmission

	Three Months Ended June 30,							Six Months Ended June 30,
	2006		2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	979	$	764	$	215		$	2,453	$	1,955	$	498
Operating expenses		622		470		152			1,690		1,259		431
Gains on sales of other assets and other, net		—		1		(1	)		29		3		26
Operating income		357		295		62			792		699		93
Other income and expenses, net		15		15		—			27		31		(4	)
Minority interest expense		11		6		5			20		15		5
EBIT	$	361	$	304	$	57		$	799	$	715	$	84
Proportional throughput, TBtu(a)		706		719		(13	)		1,669		1,775		(106	)

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

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

Operating Revenues. The increase was driven primarily by:

• A $122 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices.

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• A $47 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses).

• A $27 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union. This revenue increase is offset in expenses, and

• A $9 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• A $19 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to unseasonably warmer weather.

Operating Expenses. The increase was driven primarily by:

• A $91 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System.

• A $37 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above).

• A $27 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

• A $15 million increase in U.S. O&M primarily related to higher insurance premiums, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

• A $15 million decrease related to the resolution of prior tax years’ ad valorem tax, and

• A $15 million decrease in gas purchase costs, primarily resulting from lower gas usage due to unseasonably warmer weather.

EBIT. The increase in EBIT is due primarily to the increase in processing earnings (Empress System), U.S. business expansion and operations, the strengthening Canadian currency, and the reversal of accruals for ad valorem taxes, partially offset by increased U.S. O&M expenses.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

• A $267 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices.

• A $145 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 $102 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), and

• A $16 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• A $104 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to unseasonably warmer weather.

Operating Expenses. The increase was driven primarily by:

• A $222 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System

• A $145 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• An $81 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above) and

• A $43 million increase in U.S. O&M primarily related to higher insurance premiums, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

• An $82 million decrease in gas purchase costs, primarily resulting from lower gas usage due to unseasonably warmer weather and

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

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

Other Income and expenses, net. The decrease was driven primarily by a $5 million construction fee received 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 in 2005.

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 and the strengthening Canadian currency, partially offset by the 2005 Gulfstream success fee and Union weather and operations.

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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 business to Duke Energy shareholders. The new natural gas company, which has yet to be named, 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 $3 billion of debt currently at Duke Capital 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 and Duke Energy is targeting a January 1, 2007 effective date for the transaction. The results of the natural gas business are expected to be treated as discontinued operations in the period the spin-off is consummated.

Field Services

	Three Months Ended June 30,								Six Months Ended June 30,
	2006			2005		Increase (Decrease)			2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—		$	2,872	$	(2,872	)	$	—		$	5,530	$	(5,530	)
Operating expenses		1			2,637		(2,636	)		3			5,210		(5,207	)
Gains on sales of other assets and other, net		—			—		—			—			2		(2	)
Operating (loss) income		(1	)		235		(236	)		(3	)		322		(325	)
Equity in earnings of unconsolidated affiliates(a)		149			—		149			295			—		295
Other income and expenses, net		—			7		(7	)		—			1,258		(1,258	)
Minority interest expense		—			78		(78	)		—			497		(497	)
EBIT(a)	$	148		$	164	$	(16	)	$	292		$	1,083	$	(791	)
Natural gas gathered and processed/transported, TBtu/d(b)		6.7			6.9		(0.2	)		6.8			6.8		—
NGL production, MBbl/d(c)		365			365		—			361			362		(1	)
Average natural gas price per MMBtu(d)(e)	$	6.79		$	6.73	$	0.06		$	7.88		$	6.50	$	1.38
Average NGL price per gallon(e)	$	0.98		$	0.75	$	0.23		$	0.93		$	0.74	$	0.19

(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 for the three and six months ended June 30, 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.

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

Three months ended June 30, 2006 as Compared to June 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.

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 three months ended June 30, 2006. DEFS’ earnings during the three months ended June 30, 2006 have continued to be favorably impacted by increased commodity prices as compared to the prior period.

Other Income and expenses, net. The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Minority Interest Expense. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

EBIT. The decrease in EBIT resulted from 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 three months ended June 30, 2006 as compared to the prior period.

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Six months ended June 30, 2006 as Compared to June 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 six months ended June 30, 2005 were 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.

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 six months ended June 30, 2006. DEFS’ earnings during the six months ended June 30, 2006 have continued to be favorably impacted by increased commodity prices as compared to the prior period as well as a gain on sale of assets to an unrelated third party (of which Duke Energy’s 50% share was approximately $14 million). These increases have been partially offset by higher operating costs and pipeline integrity work for the six months ended June 30, 2006.

Other Income and expenses, net. The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. During the six months ended June 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 six months ended June 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 six months ended June 30, 2005 and 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 six months ended June 30, 2006 as compared to the prior period.

Supplemental Data

Below is supplemental information for DEFS operating results for the three and six months ended June 30, 2006:

(in millions)	Three Months Ended June 30, 2006		Six Months Ended June 30, 2006
Operating revenues	$	3,002	$	6,311
Operating expenses		2,657		5,651
Operating income		345		660
Other income and expenses, net		2		10
Interest expense, net		29		60
Income tax expense		19		20
Net income	$	299	$	590

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 business to Duke Energy shareholders. The new natural gas company, which has yet to be named, 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 and Duke Energy is targeting a January 1, 2007 effective date for the transaction.

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 is unable to express an opinion regarding the probable outcome of this matter at this time.

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Commercial Power

	Three Months Ended June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	447		$	36		$	411		$	463		$	49		$	414
Operating expenses		436			52			384			476			83			393
Losses on sales of other assets and other, net		(5	)		—			(5	)		(5	)		—			(5	)
Operating income (loss)		6			(16	)		22			(18	)		(34	)		16
Other income and expenses, net		14			—			14			11			—			11
EBIT	$	20		$	(16	)	$	36		$	(7	)	$	(34	)	$	27
Actual Plant Production, Gwh		5,363			516			4,847			5,380			706			4,674

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

Operating Revenues. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected for the three months ended June 30, 2006, but are not included in the same period in 2005. Operating revenues associated with the DENA Midwest plants were approximately $7 million lower for the three months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

Operating Expenses. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected for the three months ended June 30, 2006, but are not included in the same period in 2005. Operating expenses associated with the DENA Midwest plants were approximately $5 million lower for the three months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

EBIT. The increase was due primarily to the acquisition of Cinergy assets for which results are reflected for the three months ended 2006, but are not included in 2005. Results for the three months ended June 30, 2005 relate to the DENA Midwest assets. EBIT for these assets increased approximately $1 million for the three months ended June 30, 2006 as compared to the same period in the previous year.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by the acquisition of Cinergy assets for which results 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 $4 million lower for the six months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production

Operating Expenses. The increase was primarily driven by the acquisition of Cinergy assets for which results 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 $4 million lower for the six months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

EBIT. The increase was due primarily to the acquisition of Cinergy assets for which results are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Results for the six months ended 2005 relate to the DENA Midwest assets. EBIT for these assets decreased approximately $6 million in 2006 compared to the same period in the prior year.

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International Energy

	Three Months Ended June 30,							Six Months Ended June 30,
	2006		2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	250	$	182	$	68		$	481	$	350	$	131
Operating expenses		233		127		106			390		246		144
Operating income		17		55		(38	)		91		104		(13	)
Other income and expenses, net		11		34		(23	)		31		55		(24	)
Minority interest expense		2		3		(1	)		9		5		(4	)
EBIT	$	26	$	86	$	(60	)	$	113	$	154	$	(41	)
Sales, GWh		5,232		4,527		705			10,230		9,062		1,168
Proportional megawatt capacity in operation									3,993		4,139		(146	)

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

Operating Revenues. The increase was primarily driven by:

• A $28 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

• A $17 million increase in El Salvador due to higher energy prices and a favorable change in regulatory price bid methodology.

• A $11 million increase in Brazil mainly due to favorable exchange rates and higher average prices, and

• An $8 million increase in Argentina primarily due to higher generation and prices and increased gas marketing sales.

Operating Expenses. The increase was primarily driven by:

• A $38 million increase in Mexico due to a reserve on notes receivable from the Campeche equity investment.

• A $31 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

• A $17 million increase in El Salvador primarily due to higher fuel prices and increased fuel volumes as a result of increased generation, and

• A $14 million increase in Brazil mainly due to unfavorable exchange rates, increased transmission fees and lower costs in 2005 due to tax credit adjustment.

Other income and expenses, net. The decrease was driven primarily by a $17 million impairment of the Campeche equity investment and a $6 million decrease in Aguaytia as a result of consolidation.

EBIT. The decrease in EBIT was primarily due to an impairment of the Campeche equity investment and note receivable reserve, higher purchased power costs due to an unplanned outage in Aguaytia and unfavorable hydrology in Peru and Brazil.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by:

• A $48 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

• A $37 million increase in El Salvador mainly due to higher energy prices as a result of a favorable change in regulatory price bid methodology.

• A $25 million increase in Brazil due to favorable exchange rates, higher average energy prices, offset by lower volumes, and

• A $17 million increase in Argentina mainly due to higher energy prices and increased generation due to favorable hydrology.

Operating Expenses. The increase was primarily driven by:

• A $44 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

• A $38 million increase in Mexico mainly due to a reserve on notes receivable from the Campeche equity investment.

• A $35 million increase in El Salvador primarily due to higher fuel prices and increased fuel volumes as a result of increased generation, and

• A $20 million increase in Brazil mainly due to unfavorable exchange rates, increased transmission fees and lower costs in 2005 due to tax credit adjustment.

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Other income and expenses, net. The decrease was primarily driven by a $17 million impairment of the Campeche equity investment and an $8 million decrease in Aguaytia as a result of consolidation.

EBIT. The decrease in EBIT was primarily due to an impairment in Mexico, higher power purchases in Peru and decreased generation in Brazil, offset by favorable exchange rates primarily in Brazil and favorable hydrology and energy prices 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.

Crescent

	Three Months Ended June 30,								Six Months Ended June 30,
	2006		2005			Increase (Decrease)			2006		2005			Increase (Decrease)
	(in millions)
Operating revenues	$	85	$	112		$	(27	)	$	156	$	176		$	(20	)
Operating expenses		60		79			(19	)		121		130			(9	)
Gains on sales of investments in commercial and multi-family real estate		145		12			133			171		54			117
Operating income		170		45			125			206		100			106
Other income and expenses, net		5		(2	)		7			13		(2	)		15
Minority interest expense		1		5			(4	)		3		8			(5	)
EBIT	$	174	$	38		$	136		$	216	$	90		$	126

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

Operating Revenues. The decrease was driven primarily by a $28 million decrease in residential developed lot sales, due to decreased sales at the LandMar division in Florida, Palmetto Bluff in South Carolina and The Rim in Payson, Arizona.

Operating Expenses. The decrease was driven primarily by a $22 million decrease in the cost of residential developed lot sales as noted above.

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 as compared to minimal sales in the second quarter of 2005.

Other Income and expenses, net. The increase is primarily due to an increase of approximately $4 million in equity earnings from joint ventures and an approximate $3 million gain from the sale of an interest in a portfolio of commercial office buildings.

EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the Lake Keowee land sale as noted above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The decrease was driven primarily by a $19 million decrease in residential developed lot sales, due to decreased sales at the LandMar division in Florida and The Rim in Payson, Arizona offset by increased sales at Palmetto Bluff in South Carolina and Springfield in Charlotte, NC.

Operating Expenses. The decrease was driven primarily by a $17 million decrease in the cost of residential developed lot sales, due to decreased developed lot sales at the projects noted above. This was partially offset by a $7 million increase in administrative expenses due to incentive accruals in the first half of 2006 tied to operating results.

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 as compared to minimal sales in the first half of 2005.

Other Income and expenses, net. The increase is primarily due to an increase of approximately $10 million of equity earnings from joint ventures along with an approximate $5 million gain from the sale of an interest in a portfolio of commercial office buildings.

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EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the Lake Keowee land sale as noted above.

Matters Impacting Future Results

During the second quarter of 2006, the Board of Directors of Duke Energy authorized Duke Energy management to explore the creation of a joint venture with an undisclosed potential partner. If a joint venture is formed, it is expected that the joint venture would be levered.

Other

	Three Months Ended June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	125		$	145		$	(20	)	$	271		$	179		$	92
Operating expenses		267			252			15			468			477			(9	)
(Losses) gains on sales of other assets and other, net		(8	)		—			(8	)		(3	)		3			(6	)
Operating loss		(150	)		(107	)		(43	)		(200	)		(295	)		95
Other income and expenses, net		(27	)		2			(29	)		(39	)		5			(44	)
Minority interest benefit		(3	)		(3	)		—			(7	)		(4	)		(3	)
EBIT	$	(174	)	$	(102	)	$	(72	)	$	(232	)	$	(286	)	$	54

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

Operating Revenues. The decrease was driven primarily by the continued wind-downs of Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD), Duke Energy Trading and Marketing (DETM) and Duke Energy Merchants, LLC (DEM), partially offset by an approximate $20 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 increase was driven primarily by $74 million of charges in 2006 associated with costs to achieve the Cinergy merger, partially offset by decreases related to the continued wind-downs of D/FD, DETM and DEM, and a $20 million reduction in charges for liabilities associated with mutual insurance companies

Other Income and Expenses, net. The decrease was driven primarily by a $21 million net loss resulting from realized and unrealized mark-to-market impacts in 2006 of 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 decrease was due primarily to the charges in 2006 associated with costs to achieve the Cinergy merger, partially offset by the reduction in charges for liabilities associated with mutual insurance companies.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily 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. This increase was partially offset by decreases associated with the continued wind-downs of D/FD, DETM and DEM.

Operating Expenses. The decrease was driven primarily by a $42 million reduction in charges for liabilities associated with mutual insurance companies, including a prior year $28 million mutual insurance liability adjustment, which was a correction of an immaterial accounting error. Also contributing to the decrease were reductions associated with the continued wind-downs of D/FD, DETM and DEM. These decreases were partially offset by charges in 2006 of $78 million associated with costs to achieve the Cinergy merger.

Other Income and Expenses, net. The decrease was driven primarily by a $45 million net loss resulting from realized and unrealized mark-to-market impacts in 2006 of 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.

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EBIT. The increase was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, and lower charges for liabilities associated with mutual insurance companies. These increases were partially offset by the charges in 2006 associated with costs to achieve the Cinergy merger.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $584 million for the six months ended June 30, 2006 compared to the same period in 2005. This change was driven primarily by:

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

• The impacts of the deconsolidation of DEFS, LLC, effective July 1, 2005

• The settlement of the payable to Barclays (approximately $600 million) in 2006, partially offset by

• Collateral received by Duke Energy (approximately $540 million) in 2006 from Barclays

Investing Cash Flows

Net cash provided by investing activities increased $105 million for the six months ended June 30, 2006 compared to the same period in 2005. This change was driven primarily by:

• Approximately $1.6 billion in proceeds received from the sale of DENA in 2006, offset by approximately $1.2 billion in proceeds received in 2005 from the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP

• An approximate $147 million increase in 2006 due to cash acquired as a result of the merger with Cinergy, partially offset by

• An approximate $459 million increase in 2006 capital and investment expenditures, primarily related to Cinergy and additional investments at Crescent

Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $245 million for the six months ended June 30, 2006, compared to the same period in 2005. This change was driven primarily by:

• 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 $900 million during the six months ended June 30, 2005, compared to the repurchase of 17.5 million shares for approximately $500 million during the six months ended June 30, 2006, partially offset by

• An approximate $40 million increase in the redemptions of long-term debt in 2006, net of issuances

• An approximate $160 million increase in dividends paid due to the increase in the quarterly dividend paid per share.

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 $909 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 three and six months ended June 30, 2006, Duke Energy repurchased approximately 15.1 million and 17.5 million shares, respectively, for total consideration of approximately $430 million and $500 million, respectively. 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. Through June 30, 2006, Duke Energy has repurchased approximately 50 million shares of common stock for approximately $1.4 billion. 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.

Significant Financing Activities. During the six months ended June 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $764 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 June 2006, PSI 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.

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In August 2006, ULH&P issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance will be used to refund a like amount of debt on September 1, 2006 currently outstanding at CG&E. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

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.

In April 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. Holders of the convertible debt were able to exercise their right to convert on or prior to June 30, 2006. During the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy Common Stock. At June 30, 2006, the balance of the convertible debt is approximately $131 million and remains convertible in the third quarter of 2006 into approximately 5.6 million shares of Duke Energy common stock.

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.

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 June 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 June 2006 when S&P changed the outlook of Duke Capital Texas Eastern Transmission, LP, Union Gas and Westcoast Energy Inc. from positive to developing following Duke Energy’s announcement of the separation of the electric and gas businesses. S&P noted the developing outlook reflects a measure of uncertainty as to how the new gas company will 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 Power Company LLC and left the remaining credit ratings in the table disclosed below unchanged. At the completion of S&P’s April actions, 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 for Duke Energy and its subsidiaries (with the exception of M&N Pipeline) occurred in April 2006 following Duke Energy’s completion of the merger with Cinergy. Moody’s upgraded the credit ratings of Duke Power Company LLC (formerly rated as Duke Energy by Moody’s), 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 ratings action placing New Duke Energy and Duke Power Company 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 PSI Energy, Inc. Moody’s noted in their actions the substantial reduction in business and operating risk of Duke Power Company 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

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trading book. Moody’s also noted the upgrade at Texas Eastern, LP as connected 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 their actions with a stable outlook. Moody’s actions were 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 Pipelines, 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.

The following table summarizes the August 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 August 1, 2006

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy(a)	BBB	Baa2	Not applicable
Duke Power Company LLC(b)	BBB	A3	Not applicable
Duke Capital LLC(b)	BBB	Baa2	Not applicable
Cinergy(b)	BBB-	Baa2	Not applicable
The Cincinnati Gas & Electric Company(b)	BBB	Baa1	Not applicable
PSI Energy, Inc.(b)	BBB	Baa1	Not applicable
The Union Light, Heat and Power Company(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.

Prior to June 30, 2006, business activity by DENA generated the majority of Duke Energy’s collateral requirements. 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 Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as associated contracts. The sale is subject to Federal Energy Regulatory Commission and Federal Reserve Board approvals, as well as Canadian regulatory approvals, and is anticipated to close in the third quarter of 2006. Once closed, the buyer will assume the credit, collateral, market and legal risk associated with the trading positions acquired.

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A reduction in the credit rating of Cinergy Corp to below investment grade as of June 30, 2006 would have required the posting of additional collateral of up to approximately $260 million, of which $82 million is related to CG&E, a wholly-owned subsidiary of Cinergy Corp.

A reduction in the credit rating of Duke Capital to below investment grade as of June 30, 2006 would have resulted in Duke Capital posting additional collateral of up to approximately $320 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 June 30, 2006, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,790 million in gross proceeds from debt and other securities, which include approximately $1,248 million of effective registrations at legacy Cinergy. Additionally, as of June 30, 2006, Duke Energy had 700 million Canadian dollars (approximately U.S. $618 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 700 million Canadian dollars available under Canadian shelf registrations, 200 million expired in July 2006 and 500 million expires in May 2008. In July 2006, an additional 600 million Canadian dollars (approximately U.S. $529) was added to the amount available under Canadian shelf registrations that expires in August 2008.

Off-Balance Sheet Arrangements

During the six months ended June 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 (QSPE) pursuant to SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” 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 six months ended June 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 $6.7 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 business to Duke Energy shareholders. The new gas company, which has yet to be named, will consist of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and Duke Energy’s 50-percent ownership interest in Duke Energy Field Services (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 Crescent Resources. Approximately $3 billion of debt currently at Duke Capital is anticipated to transfer to the new natural gas company at the time of the spin-off. Duke Energy is targeting a January 1, 2007 effective date for the transaction and expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders. The transaction would require Virginia State Corporation Commission approval and Duke Energy applied for such approval on August 1, 2006. In addition, approval from the Federal Communications Commission would be required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy expects to make the requisite applications in the third quarter 2006.

(For additional information on other issues related to Duke Energy, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters.”)

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New Accounting Standards

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of June 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, “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. This Statement 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. This Statement 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.

FASB Interpretation 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 fiscal years beginning after December 15, 2006. 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. FIN 46 (R)-6, “Determining the Variability to Be Considered In Applying Interpretation No. 46(R) (FSP-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 FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities. The variability that is considered in applying Interpretation 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 will be applied prospectively to all entities with which Duke Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. Duke Energy does not anticipate the adoption of FSP No. FIN 46 (R)-6 will have any material impact on its 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 05-1). In June 2006, the EITF reached a consensus on Issue 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 securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus is effective for Duke Energy for all conversions within its scope that result from the exercise of call options beginning July 1, 2006. Duke Energy does not anticipate the adoption of EITF Issue 05-1 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 06-3). In June 2006, the EITF reached a consensus on Issue 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

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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., include 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 Issue 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, debt and credit facilities, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and related party transactions, see Note 2, “Acquisitions and Dispositions,” Note 7, “Debt and Credit Facilities,” Note 13, “Discontinued Operations and Assets Held For Sale,” 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 June 30, 2006, it was estimated that price changes of eighteen cents per gallon and 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 $167 million and $143 million, respectively 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 June 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 CG&E’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 is anticipated to close in the third quarter of 2006.

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

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(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

	June 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 Second Quarter 2006	High One-Day Impact on Pre-tax Income from Continuing Operations for Second Quarter 2006	Low One-Day Impact on Pre-tax Income from Continuing Operations for Second Quarter 2006
	(in millions)
Calculated VaR	$5	$5	$13	$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 June 30, 2006 was not material.

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.

Duke disclosed a DER of $12 million as of December 31, 2005. This was primarily comprised of DENA derivative positions. DENA’s DER at June 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.

Duke Energy Trading & Marketing (“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

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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 June 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 June 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 June 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of June 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. 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 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 June 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 June 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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings that became reportable events or in which there were material developments in the second quarter of 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 Report on Form 10-Q for the period ended March 31, 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 correctly 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 Second Quarter of 2006

Period	Total Number of Shares (or Units) Purchaseda	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programsa	Approximate Dollar Value of Shares (or Units) that May Yet Be Purchased Under Plans or Programsa (in billions)
April 1 to April 30	4,067,400	$	28.97	4,067,400	$	1.4
May 1 to May 31	6,246,200	$	28.13	6,246,200	$	1.2
June 1 to June 30	4,777,000	$	28.56	4,777,000	$	1.1

a 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 three month period ended June 30, 2006, Duke Energy repurchased approximately 15.1 million shares for approximately $0.4 billion (see Note 4 to the Consolidated Financial Statements, “Common Stock”). Through June 30, 2006, Duke Energy has repurchased approximately 50 million shares of common stock for approximately $1.4 billion under this repurchase plan. In connection with the plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders, the share repurchase program has since been suspended.

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 second quarter of 2006.

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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
3.1	Amended and Restated Certificate of Incorporation (filed with Form 8-K of registrant, File No. 1-32853, April 4, 2006, as exhibit 3.1)
3.2	Amended and Restated By-Laws (filed with Form 8-K of registrant, File No. 1-32853, April 4, 2006, as exhibit 3.2)
*10.1	Fifteenth Supplemental Indenture, dated as of April 3, 2006, among the registrant, Duke Energy and JPMorgan Chase Bank, N.A. (as successor to Guaranty Trust Company of New York), as trustee (the “Trustee”), supplementing the Senior Indenture, dated as of September 1, 1998, between Duke Power Company LLC (formerly Duke Energy Corporation) and the Trustee
10.3	Amendment to Purchase and Sale Agreement, dated as of May 4, 2006, by and among Duke Energy Americas, LLC, LS Power Generation, LLC (formerly known as LSP Bay II Harbor Holding, LLC), LSP Gen Finance Co, LLC, LSP South Bay Holdings, LLC, LSP Oakland Holdings, LLC, and LSP Morro Bay Holdings, LLC
10.4**	Form of Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as exhibit 10.1)
10.5**	Form of Performance Share Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as exhibit 10.2)
10.6**	Employment Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.1)
10.7**	Performance Award Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.2)
10.8**	Phantom Stock Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.3)
10.9**	Stock Option Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.4)
10.10**	Second Amendment to Employment Agreement, dated as of April 4, 2006, by and among Paul M. Anderson, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation) and Duke Energy Corporation (subsequently renamed Duke Power LLC) (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.5)
10.11**	Retention Award Agreement between Duke Energy Corporation and David L. Hauser, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.6)
10.12**	Severance and Retention Agreement between Duke Energy Corporation and Ruth Shaw, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.7)
*10.13**	Summary of Director Compensation
10.14**	Form Phantom Stock Award Agreement and Election to Defer (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 16, 2006, as exhibit 10.1)
*10.15	Agreements with Piedmont Electric Membership Corporation, Rutherford Electric Membership Corporation and Blue Ridge Electric Membership Corporation to provide wholesale electricity and related power scheduling services from September 1, 2006 through December 31, 2021

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Exhibit Number
10.16	Agreement with Dynegy Inc. and Rockingham Power, L.L.C. to acquire an approximately 825 megawatt power plant located in Rockingham County, N.C. for approximately $195 million (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 25, 2006, as exhibit 10.1)
10.17	Purchase and Sale Agreement by and among Cinergy Capital & Trading, Inc., as Seller, and Fortis Bank, S.A./N.V., as Buyer, dated as of June 26, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, June 30, 2006, as exhibit 10.1)
*10.18	Amended and Restated Credit Agreement, dated June 29, 2006, among Cinergy Corp., CG&E, PSI, ULH&P, The Banks Listed Herein, Barclays Bank PLC, as Administrative Agent, and JPMorgan Chase Bank, N.A., as Syndication Agent.
*10.19	Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Capital LLC, The Banks Listed Herein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent.
*10.20	Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Power Company LLC, The Banks Listed Herein, Citibank N.A., as Administrative Agent, and Banc of America, N.A., as Syndication Agent.
*31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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SIGNATURES

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

	DUKE ENERGY CORPORATION
Date: August 9, 2006	/s/    DAVID L. HAUSER
	David L. Hauser Group Executive and Chief Financial Officer
Date: August 9, 2006	/s/    STEVEN K. YOUNG
	Steven K. Young Vice President and Controller

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