8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of report: December 9, 2005

(Date of earliest event reported:)

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in charter)

NORTH CAROLINA	1-4928	56-0205520
(State or other jurisdiction of incorporation)	(Commission File No.)	(IRS Employer Identification No.)

526 South Church Street Charlotte, North Carolina	28202-1803
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 704-594-6200

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

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

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

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

• The weather and other natural phenomena, including the economic, operational and other effects of Hurricanes Katrina and Rita

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

• General economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which Duke Energy has no control

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

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

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

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

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

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

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

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

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

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

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

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

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

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ITEM 8.01 Other Events

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

The DENA assets to be divested include:

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

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

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

The results of operations of DENA’s western and eastern United States generation assets, including related commodity contracts, the Ft. Frances generation assets, substantially all of the contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be presented as discontinued operations in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” Duke Energy’s Form 10-Q for the quarter ended September 30, 2005 reflects these operations as discontinued for all periods presented and DENA’s continuing operations are retrospectively reported as Other for Duke Energy’s segment disclosures beginning in 2005.

Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Duke Energy’s Natural Gas Transmission segment. Prior period segment results for Natural Gas Transmission were retrospectively adjusted in Duke Energy’s Form 10-Q for the quarter ended September 30, 2005 to include the McMahon facility.

Also during the third quarter of 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in Duke Energy Field Services LLC (DEFS) from 69.7% to 50%. In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Duke Energy’s Form 10-Q for the quarter ended September 30, 2005 reflects segment results for Field Services excluding the results of operations of these Canadian gathering and processing facilities, while segment results for Natural Gas Transmission were adjusted to include the results of operations of these Canadian gathering and processing facilities for all periods presented.

The rules of the Securities and Exchange Commission (SEC) require the re-issue of Duke Energy’s previously issued financial statements to reflect the subsequent reclassification of operations to discontinued operations if those financial statements are incorporated by reference in subsequent filings made with the SEC under the Securities Act of 1933, as amended. Accordingly, Duke Energy is re-issuing its historical Selected Financial Data, Financial Statements and Supplementary Data, and Management’s Discussion and Analysis of Financial Condition and Results of Operations for each of the three years in the period ending December 31, 2004 (five years for the purposes of Selected Financial Data), the three months ending March 31, 2005 and the three and six months ending June 30, 2005 to conform prior periods to the current reporting structure as described above. The information in this Form 8-K updates and supercedes Part II, Items 6, 7, 7a and 8 and Exhibit 12, Computation of Ratio of Earnings to Fixed Charges, of Duke Energy’s Form 10-K for the year ended December 31, 2004 and also updates and supercedes Part I, Items 1, 2 and 3 of Duke Energy’s Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.

Subsequent events occurring since the original filing dates have been updated from those presented in Duke Energy’s original Form 10-K for the year ended December 31, 2004, Form 10-Q for the quarter ended March 31, 2005 and Form 10-Q for the quarter ended June 30, 2005 for the items described above. Additionally, subsequent events in Duke Energy’s Form 10-K for the year ended December 31, 2004 and Form 10-Q for the quarter ended March 31, 2005 have been updated for the planned Cinergy merger. No attempt has been made in this Form 8-K to modify or update other disclosures as presented in the original filings. These revisions do not affect consolidated net income, total assets, total liabilities or stockholders’ equity.

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ITEM 9.01 Financial Statements And Exhibits.

Exhibit Number
99.1	For the year ended December 31, 2004:
	Part II, Item 6: Selected Financial Data
	Part II, Item 7: Management’s Discussion and Analysis of Results of Operations and Financial Condition
	Part II, Item 7A: Quantitative and Qualitative Disclosures About Market Risk
	Part II, Item 8: Financial Statements and Supplementary Data
	Part IV, Exhibits and Financial Statement Schedule, Exhibit No. 12, Computation of Ratio of Earnings to Fixed Charges
99.2	For the quarter ended March 31, 2005:
	Part I, Item 1: Financial Statements
	Part I, Item 2: Management’s Discussion and Analysis of Results of Operations and Financial Condition
	Part I, Item 3: Quantitative and Qualitative Disclosures About Market Risk
99.3	For the quarter ended June 30, 2005:
	Part I, Item 1: Financial Statements
	Part I, Item 2: Management’s Discussion and Analysis of Results of Operations and Financial Condition
	Part I, Item 3: Quantitative and Qualitative Disclosures About Market Risk
99.4	Consent of Independent Registered Public Accounting Firm

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SIGNATURE

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 hereunto duly authorized.

Date: December 9, 2005	DUKE ENERGY CORPORATION
	By:	/s/ Steven K.Young
		Steven K. Young Vice President and Controller

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EXHIBIT INDEX

Exhibit Number		Page Number
99.1	For the year ended December 31, 2004:
	Part II, Item 6: Selected Financial Data	7
	Part II, Item 7: Management’s Discussion and Analysis of Results of Operations and Financial Condition	8
	Part II, Item 7A: Quantitative and Qualitative Disclosures About Market Risk	48
	Part II, Item 8: Financial Statements and Supplementary Data	48
	Part IV, Exhibits and Financial Statement Schedule, Exhibit No. 12, Computation of Ratio of Earnings to Fixed Charges	131
99.2	For the quarter ended March 31, 2005:
	Part I, Item 1: Financial Statements	132
	Part I, Item 2: Management’s Discussion and Analysis of Results of Operations and Financial Condition	166
	Part I, Item 3: Quantitative and Qualitative Disclosures About Market Risk	185
99.3	For the quarter ended June 30, 2005:
	Part I, Item 1: Financial Statements	187
	Part I, Item 2: Management’s Discussion and Analysis of Results of Operations and Financial Condition	223
	Part I, Item 3: Quantitative and Qualitative Disclosures About Market Risk	246
99.4	Consent of Independent Registered Public Accounting Firm

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EX-99.1

Exhibit 99.1

Part II, Item 6. Selected Financial Data^(a).

	2004			2003(b)			2002			2001			2000
	(in millions, except per share amounts)
Statement of Operations
Operating revenues	$	20,549		$	18,021		$	14,752		$	15,383		$	14,190
Operating expenses		17,376			17,087			12,393			13,036			11,179
Gains on sales of investments in commercial and multi-family real estate		192			84			106			106			75
(Losses) gains on sales of other assets, net		(404	)		(199	)		32			238			214
Operating income (loss)		2,961			819			2,497			2,691			3,300
Other income and expenses, net		305			550			369			293			703
Interest expense		1,281			1,330			1,116			777			863
Minority interest expense		200			62			91			268			288
Earnings (loss) from continuing operations before income taxes		1,785			(23	)		1,659			1,939			2,852
Income tax expense (benefit) from continuing operations		533			(94	)		514			713			983
Income (loss) from continuing operations		1,252			71			1,145			1,226			1,869
Income (loss) from discontinued operations, net of tax		238			(1,232	)		(111	)		768			(93	)
Income (loss) before cumulative effect of change in accounting principle		1,490			(1,161	)		1,034			1,994			1,776
Cumulative effect of change in accounting principle, net of tax and minority interest		—			(162	)		—			(96	)		—
Net income (loss)		1,490			(1,323	)		1,034			1,898			1,776
Dividends and premiums on redemption of preferred and preference stock		9			15			13			14			19
Earnings (loss) available for common stockholders	$	1,481		$	(1,338	)	$	1,021		$	1,884		$	1,757
Ratio of Earnings to Fixed Charges		2.4			—	(d)		2.1			2.8			3.8
Common Stock Data(c)
Shares of common stock outstanding
Year-end		957			911			895			777			739
Weighted average		931			903			836			767			736
Earnings (loss) per share (from continuing operations)
Basic	$	1.33		$	0.06		$	1.35		$	1.58		$	2.51
Diluted		1.29			0.06			1.35			1.57			2.50
Earnings (loss) per share (from discontinued operations)
Basic	$	0.26		$	(1.36	)	$	(0.13	)	$	1.00		$	(0.12	)
Diluted		0.25			(1.36	)		(0.13	)		0.99			(0.12	)
Earnings (loss) per share (before cumulative effect of change in accounting principle)
Basic	$	1.59		$	(1.30	)	$	1.22		$	2.58		$	2.39
Diluted		1.54			(1.30	)		1.22			2.56			2.38
Earnings (loss) per share
Basic	$	1.59		$	(1.48	)	$	1.22		$	2.45		$	2.39
Diluted		1.54			(1.48	)		1.22			2.44			2.38
Dividends per share		1.10			1.10			1.10			1.10			1.10
Balance Sheet
Total assets	$	55,470		$	57,225		$	60,122		$	49,624		$	59,276
Long-term debt including capital leases, less current maturities	$	16,932		$	20,622		$	20,221		$	12,321		$	10,717

(a) Amounts have been retrospectively adjusted to reflect certain operations as discontinued operations (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for the Years Ended December 31, 2004, 2003 and 2002).

(b) As of January 1, 2003, Duke Energy adopted the remaining provisions of Emerging Issues Task Force (EITF) Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” and SFAS No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles. (See Note 1 to the Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002, “Summary of Significant Accounting Policies,” for further discussion.)

(c) Amounts prior to 2001 were retrospectively adjusted to reflect the two-for-one common stock split effective January 26, 2001.

(d) Earnings were inadequate to cover fixed charges by $19 million for the year ended December 31, 2003.

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Part II, Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition.

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the Years Ended December 31, 2004, 2003 and 2002.

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

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). In connection with the Duke Energy Field Services LLC (DEFS) disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

Overview of Business Strategy. Duke Energy’s business strategy is to create value for customers, employees, communities and shareholders through the production, conversion, delivery and sale of energy and energy services. Duke Energy’s plan is to emphasize income for its shareholders, with modest growth.

For the past few years, the energy industry including Duke Energy experienced a number of challenges, including the substantial imbalance between supply and demand for electricity, the pace of economic recovery, and regulatory and legal uncertainties. In response to these challenges, Duke Energy’s focus for 2004 was to reduce risks and restructure its business. By selling assets such as DENA’s eight natural gas-fired merchant power plants: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi) in the southeastern United States; (collectively, the Southeast Plants) and International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business), Duke Energy eliminated some of its lowest return assets. These asset sales provided cash proceeds allowing Duke Energy to pay down debt and strengthen its balance sheet. Progress was also made in 2004 in resolving some critical legal and regulatory issues.

As a result of the efforts in 2004, Duke Energy’s objectives for 2005 include establishing industry-leading positions in core businesses and identifying new energy-related growth strategies, focused in the Americas. Increased demand for natural gas supplies in the United States and changing logistics among source of supply are providing opportunities for growth. To capitalize on this market dynamic, Natural Gas Transmission is evaluating longer-term opportunities to provide pipeline capacity and storage facilities for the expected expansion of the liquefied natural gas (LNG) market. Additionally, the strength of the natural gas market provides incentives for producers to increase exploration and production, which in turn, provides business sustainability and growth opportunities for Field Services. Duke Power and International Energy are expected to grow organically for the near term.

In February 2005, DEFS sold Texas Eastern Products Pipeline Company LLC (TEPPCO) for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions closed in the first quarter of 2005.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction, which is expected to occur in the latter half of 2005.

Duke Energy believes merchant energy will play a vital role in meeting the United States’ energy demand. Another key objective for 2005 is to position DENA to be a successful merchant operator. During 2004, DENA’s business model changed to focus on selling fixed capacity contracts in addition to volume based sales and purchases. Duke Energy is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. A sustainable business model will include fuel and geographic diversity, sufficient size and scope for a substantial market presence and will enable DENA to better withstand the cyclical nature of the industry. Depending on the option selected, there is a risk that material impairments or losses could be recorded, including the potential disqualification of certain contracts and the recognition of unrealized losses associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption, which totaled approximately $900 million (pre-tax) as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the

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forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $800 million (pretax) as of December 31, 2004. (For more information see Commodity Price Risk discussion under Quantitative and Qualitative Disclosures About Market Risk). See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

With cash, cash equivalents and short-term investments on hand at December 31, 2004 of approximately $1.9 billion and a more stable business environment, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy is evaluating these options and will determine the best economic decisions to meet the needs of shareholders and ensure the long-term financial strength of Duke Energy. In connection with the TEPPCO and DEFS transactions discussed above, Duke Energy has announced plans to periodically repurchase up to an aggregate $2.5 billion of its common stock over the next three years.

Other key objectives for Duke Energy in 2005 are to build stakeholder relationships through effective leadership on key policy issues related to energy, regulation and the environment, and also to focus on safety, inclusion and diversity, employee development, business structure and process simplification.

These objectives, along with delivering on Duke Energy’s financial plan, are set with the intent to provide superior total shareholder return.

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable, less cyclical businesses like Franchised Electric and Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy businesses like DENA, International Energy and Field Services. Additionally, Crescent Resources LLC’s (Crescent’s) portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market price of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2005 and beyond.

Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Energy’s cash flows; especially as industrial customers reduce production and, thus, consumption of electricity. A portion of Franchised Electric’s business risk is mitigated by its being subject to regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses. Natural Gas Transmission is also subject to mandated tariff rates and recovery of certain fuel costs. Lower economic output would also cause the Natural Gas Transmission and Field Services businesses to experience a decline in the volume of natural gas shipped through their pipelines, gathered and processed at their plants, or distributed by their local distribution company, resulting in lower revenue and cash flows. Natural Gas Transmission continues to experience positive renewals of its customer contracts as they expire.

If negative market conditions persist over time and estimated cash flows over the lives of Duke Energy’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in impairments or losses.

Duke Energy’s goals for 2005 can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in North America are subject to regulations on the federal and state level. The majority of Duke Energy’s Canadian natural gas assets is also subject to various degrees of federal or provincial regulation and is subject to the same risks. Regulations, applicable to the electric power industry and gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

Additionally, Duke Energy’s investments and projects located outside of the United States expose it to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Energy’s future results. Duke Energy’s recent restructuring, which focuses its non-United States operations on only Latin America and Canada, will help mitigate this exposure.

Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by the cash flow from its operations. If Duke Energy is not able to access capital at competitive rates, its ability to implement its strategy could be adversely affected. Market disruptions or a downgrade of Duke Energy’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.

RESULTS OF OPERATIONS

Overview of Drivers and Variances for 2004 and 2003

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, earnings available for common stockholders were $1,481 million, or $1.59 per basic share and $1.54 per diluted share. For 2003, earnings available for

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common stockholders were a loss of $1,338 million, or a loss of $1.48 per basic and diluted share. Significant items that contributed to the improved results in 2004 included:

• Pre-tax charges of $2.8 billion (of which $1.3 billion related to discontinued operations) in 2003 related to asset impairments of: DENA’s Southeast Plants which were sold during 2004, DENA’s partially completed Western plants (which were classified as discontinued operations and two of which were subsequently sold in 2004), and wind-down costs associated with the Duke Energy Trading and Marketing LLC (DETM) joint venture

• A $295 million pre-tax gain ($273 million net of tax) recorded in 2004 on the sale of International Energy’s Asia-Pacific Business, slightly offset by a loss on its European gas trading and marketing business (European Business), both businesses were classified as discontinued operations

• Net pre-tax charges and impairments of $292 million ($223 million net of tax) in 2003 for International Energy’s Asia-Pacific and European Businesses, which were classified as discontinued operations and subsequently sold in 2004

• Pre-tax charges of $262 million in 2003 for the disqualification of certain hedges and contracts that were being accounted for as normal purchases and normal sales from the Accrual Model to the MTM Model that were related to the impaired assets at DENA ($452 million of this charge related to discontinued operations and a benefit of $190 million related to continuing operations)

• A pre-tax charge of $254 million in 2003 for goodwill impairment at DENA, related primarily to the trading and marketing business

• Pre-tax gains in 2004 of $180 million ($117 million after tax) on the sales of two partially completed western plants at DENA which were classified as discontinued operations

• Charges in 2003 related to changes in accounting principles of $162 million, net of tax and minority interest

• Pre-tax severance and related charges of $153 million in 2003 associated with workforce reductions across all segments, net of minority interest of $2 million

• A $130 million (net of minority interest of $5 million) pre-tax gain in 2004 related to the settlement of the Enron bankruptcy proceedings ($101 million of this charge related to discontinued operations and $29 million related to continuing operations)

• A $64 million pre-tax decrease in 2004 Operating Expenses as a result of the correction of an accounting error in prior periods related to reserves at Bison Insurance Company Limited (Bison) for property losses at several Duke Energy subsidiaries

• The reduction of various income tax reserves in 2004 totaling approximately $52 million (see Note 6 to the Consolidated Financial Statements, “Income Taxes”)

• A pre-tax charge of $51 million in 2003 for the write-off of an abandoned corporate risk management information system

• A $48 million tax benefit in 2004 related to the realignment of certain subsidiaries of Duke Energy and the pass-through structure of these for U.S. income tax purposes ($20 million of this amount related to continuing operations, see Note 6 to the Consolidated Financial Statements, “Income Taxes,” and $28 million related to discontinued operations)

• A regulatory action by the Public Service Commission of South Carolina (PSCSC) in 2003 which resulted in decreased pre-tax earnings of $46 million at Franchised Electric, $16 million of which was due to an order to write-off regulatory assets related to debt issuance costs through interest expense

• Increased 2004 earnings at Field Services due to favorable effects of commodity prices and improved results from trading and marketing activities, and

• Increased residential developed lot sales, commercial project and land management (“legacy” land sales) at Crescent, due to several large sales that closed in 2004.

Partially offsetting these increases and prior year charges were:

• An approximate $360 million pre-tax charge in the first quarter of 2004 associated with the sale of DENA’s Southeast Plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”)

• A $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel)

• A $105 million pre-tax charge in 2004 related to the California and western U.S. energy markets settlement (this amount was included in discontinued operations; see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”)

• A $52 million income tax benefit in 2003 related to the write-off of goodwill at International Energy’s European Business in 2002, and

• An increase of $45 million related to taxes recorded in 2004 on the repatriation of foreign earnings that is expected to occur in 2005 associated with the American Jobs Creation Act

For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the impact of changes in accounting principles, see “Other Impacts on Earnings Available for Common Stockholders” at the end of this section.

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Consolidated Operating Revenues

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating revenues for 2004 increased $2,528 million, compared to 2003. This change was driven by:

• A $2,144 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues due to higher average NGL and natural gas prices at Field Services, partially offset by the continued wind-down of DETM and Duke Energy Merchants, LLC (DEM)

• A $190 million increase in Regulated Electric revenues, due primarily to increased fuel rates charged to retail customers as a result of increased coal costs and increased sales resulting from favorable weather at Franchised Electric. The increase was also attributable to the continued growth in the number of Franchised Electric residential and general service customers, and

• A $194 million increase in Regulated Natural Gas revenues, due primarily to the strengthening Canadian dollar at Natural Gas Transmission.

Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating revenues for 2003 increased $3,269 million, compared to 2002. This change was primarily driven by:

• A $2,388 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues, due primarily to increased NGL pricing, and

• An $829 million increase in Regulated Natural Gas revenues due primarily to increased transportation, storage and distribution revenues from assets acquired or consolidated as a part of the acquisition of Westcoast Energy Inc. (Westcoast) in March 2002.

Consolidated Operating Expenses

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating expenses for 2004 increased $289 million, compared to 2003. The change was primarily driven by:

• A $1,677 million increase in Natural Gas and Petroleum Products Purchased due primarily to higher average NGL and natural gas prices at Field Services, offset by

• A $111 million increase in Fuel Used in Electric Generation and Purchased Power, primarily due to increased coal costs and increased sales at Franchised Electric

• A $1,155 million decrease in Impairments and Other Related Charges due primarily to charges of $1,166 in 2003 resulting from strategic actions taken at DENA which led to the recording of impairments primarily related to the Southeast Plants, offset by $65 million of impairments in 2004 at Field Services and Crescent.

• A $179 million decrease in Operation, Maintenance and Other due primarily to severance costs accrued in 2003 related to workforce reductions and decreased operating and maintenance cost at DENA resulting from cost reduction efforts and the sale of plants in 2004, partially offset by increased costs at Crescent related to increased residential developed lot sales, and

• A $254 million decrease due to the 2003 write off of goodwill at DENA, most of which related to DENA’s trading and marketing business.

Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating expenses for 2003 increased $4,694 million, compared to 2002. The increase in consolidated operating expenses was driven primarily by impairments and other related charges, and by the same drivers that affected consolidated operating revenues: increased purchase costs for NGLs and additional expenses due to the acquisition of Westcoast.

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

Consolidated gains on sales of investments in commercial and multi-family real estate were $192 million in 2004, $84 million in 2003, and $106 million in 2002. For a detailed discussion of this item see the Crescent segment discussion below.

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

Consolidated (losses) gains on sales of other assets, net was a loss of $404 million for 2004, a loss of $199 million for 2003, and a gain of $32 million for 2002. The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at DENA, and the termination and sale of DETM contracts ($65 million). The loss for 2003 was primarily comprised of a $208 million loss at DENA primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM’s operations, and impairments recorded on assets held for sale, including a 25% undivided interest in the wholly-owned Vermillion facility ($18 million), and stored turbines and related equipment ($66 million). The gain for 2002 was primarily comprised of a $33 million gain on the sale of Duke Energy’s remaining water operations.

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Consolidated Operating Income

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated operating income increased $2,142 million, compared to 2003. Increased operating income was driven primarily by increased operating income at DENA, as a result of impairments and other related charges in 2003.

Year Ended December 31, 2003 as Compared to December 31, 2002. For 2003, consolidated operating income decreased $1,678 million, compared to 2002. Lower operating income was driven primarily by asset impairments and related charges at DENA of $1,166 million, as discussed above.

Consolidated Other Income and Expenses

Consolidated other income and expenses decreased $245 million for the year ended December 31, 2004 as compared to December 31, 2003. The decrease primarily resulted from the $178 million pre-tax gain on the sale of DENA’s 50% interest in Ref-Fuel in 2003 and Natural Gas Transmission’s $90 million gain on sales of various investments in 2003, offset by foregone earnings from those investments. The increase in 2003 compared to 2002 was also a result of the gain from the Ref-Fuel sale as discussed above.

Segment Results

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

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

EBIT by Business Segment

	Years Ended December 31,
	2004			2003			Variance 2004 vs 2003			2002			Variance 2003 vs 2002
	(in millions)
Franchised Electric	$	1,467		$	1,403		$	64		$	1,595		$	(192	)
Natural Gas Transmission		1,329			1,333			(4	)		1,170			163
Field Services		368			176			192			139			37
DENA		(585	)		(1,676	)		1,091			(75	)		(1,601	)
International Energy		222			215			7			102			113
Crescent		240			134			106			158			(24	)
Total reportable segment EBIT		3,041			1,585			1,456			3,089			(1,504	)
Other		(77	)		(272	)		195			(368	)		96
Total reportable segment and other EBIT		2,964			1,313			1,651			2,721			(1,408	)
Minority interest expense and other(a)		102			(6	)		108			54			(60	)
Interest expense		(1,281	)		(1,330	)		49			(1,116	)		(214	)
Consolidated earnings (loss) from continuing operations before income taxes	$	1,785		$	(23	)	$	1,808		$	1,659		$	(1,682	)

(a) Includes interest income, foreign currency remeasurement 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.

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Franchised Electric

	Years Ended December 31,
	2004		2003		Variance 2004 vs 2003			2002		Variance 2003 vs 2002
	(in millions)
Operating revenues	$	5,069	$	4,875	$	194		$	4,888	$	(13	)
Operating expenses		3,613		3,525		88			3,329		196
Gains on sales of other assets, net		3		6		(3	)		—		6
Operating income		1,459		1,356		103			1,559		(203	)
Other income, net of expenses		8		47		(39	)		36		11
EBIT	$	1,467	$	1,403	$	64		$	1,595	$	(192	)
Sales, Gigawatt-hours (GWh)		82,708		82,828		(120	)		83,783		(955	)

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

Increase (decrease) over prior year	2004		2003		2002
Residential sales(a)	5.1	%	(2.3	)%	5.2	%
General service sales(a)	3.5	%	0.4	%	2.4	%
Industrial sales(a)	1.8	%	(5.7	)%	(2.4	)%
Wholesale sales	(26.1	)%	5.1	%	35.4	%
Total Franchised Electric sales(b)	(0.1	)%	(1.1	)%	5.1	%
Average number of customers	1.7	%	2.0	%	2.4	%

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

(b) Consists of all components of Franchised Electric’s sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $138 million increase in billed and unbilled fuel revenues driven by increased fuel rates for retail customers, due primarily to increased coal costs

• A $68 million increase in GWh sales to retail customers, due to favorable weather during the period

• A $33 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory

• A $30 million increase due to a rate decrement ordered by the PSCSC and recorded during the third quarter of 2003, partially offset by

• A $50 million decrease in wholesale power revenues, due primarily to lower sales volumes due to limited generation availability resulting from a shortage of coal and increased outages at certain Franchised Electric generation facilities, and

• An $18 million decrease due to sharing of profits from wholesale power sales with customers in North Carolina in 2004.

Operating Expenses. The increase was driven primarily by:

• Increased fuel expenses of $127 million, due primarily to increased coal costs and increased sales to retail customers

• Increased nuclear and fossil outage costs of $24 million, driven by increased scope and duration of 2004 nuclear outages compared to 2003 and seven planned maintenance/turbine outages across the fossil fleet in 2004 as compared to two planned maintenance/turbine outages in 2003

• Increased depreciation expense of $16 million, primarily due to additional capital spending and assets placed in service

• Increased donations of $14 million, due to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina as agreed to with the state utility commission, partially offset by

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• Decreased severance expenses of $78 million due to workforce reductions in 2003, and

• Decreased operating and maintenance expenses of $9 million, primarily due to a charge in 2003 for right-of-way maintenance costs, partially offset by increased governance costs in 2004.

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

• A $25 million decrease in the allowance for funds used during construction (AFUDC), due primarily to large maintenance capital projects that were completed and placed in service in 2003, reducing the basis on which AFUDC is calculated, and

• A $15 million decrease in the return on deferred costs related to the purchase of capacity from the joint owners of the Catawba Nuclear Station.

EBIT. The increase in 2004 EBIT resulted primarily from increased sales to retail customers due to favorable weather in 2004, continued growth in the number of residential and general service customers in 2004, and severance and right-of-way maintenance charges coupled with the one year rate decrement ordered by the PSCSC during 2003. These changes were partially offset by lower sales to wholesale customers, sharing of profits from wholesale power sales, increased fossil and nuclear outages and increased depreciation expense.

Matters Impacting Future Franchised Electric Results

Franchised Electric continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Piedmont Carolinas. The residential and general service sectors are expected to continue to grow. As noted above, wholesale power revenues declined during 2004 due to coal inventory shortages resulting from delivery constraints. Coal deliveries have since improved and Franchised Electric expects to have increased wholesale opportunities as coal inventories increase. Franchised Electric’s EBIT growth rate over the next three years is expected to be in the zero to two percent range. Franchised Electric will continue to provide strong cash flows to Duke Energy. Changes in weather, wholesale power market prices, generation availability and changes to the regulatory environment could impact future financial results for Franchised Electric. In addition, Franchised Electric’s results will be affected by its flexibility to vary the amortization expenses associated with the North Carolina clean air legislation. Franchised Electric’s amortization expense related to this clean air legislation totals $326 million from inception, with $211 million recorded in 2004 and $115 million recorded in 2003.

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The decrease was driven primarily by:

• An $80 million decrease from lower GWh sales to retail customers due to mild weather, particularly during the summer months of 2003

• A $30 million decrease due to a one year rate decrement ordered by the PSCSC during the third quarter of 2003

• A $28 million decrease in sales to industrial customers, which continued to decline due to the sluggish economy in North Carolina and South Carolina, partially offset by

• An $87 million increase from wholesale power sales, as a result of favorable market conditions. The primary driver was higher prices for natural gas, which increased both the market price and demand for wholesale power, coupled with availability of low cost generation (primarily coal-fired generation for Franchised Electric), and

• A $38 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory.

Operating Expenses. The increase was driven primarily by:

• Increased depreciation and amortization expense of $137 million, primarily driven by amortization expense related to North Carolina’s clean air legislation, which totaled $115 million

• Increased severance expenses of $42 million due to additional workforce reductions in 2003

• Charges in 2003 of $40 million for right-of-way maintenance costs, partially offset by

• Insurance recoveries in 2002 of $25 million related to injuries and damages claims

• Decreased storm costs of $59 million, with $30 million incurred in 2003 compared to $89 million associated with an ice storm in December 2002, and

• Decreased purchased power expense of $12 million, driven by lower demand from retail customers due to the milder weather.

EBIT. EBIT for 2003 decreased $192 million, compared to 2002, due primarily to unfavorable weather, the one year South Carolina rate decrement and lower sales to industrial customers, coupled with increased depreciation and amortization expense, severance expenses and right-of-way maintenance costs. These changes were partially offset by increased wholesale power sales, continued growth in the number of residential and general service customers, and lower storm and purchased power expenses.

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Natural Gas Transmission

	Years Ended December 31,
	2004		2003		Variance 2004 vs 2003			2002		Variance 2003 vs 2002
	(in millions)
Operating revenues	$	3,351	$	3,253	$	98		$	2,506	$	747
Operating expenses		2,075		2,009		66			1,449		560
Gains on sales of other assets, net		17		7		10			—		7
Operating income		1,293		1,251		42			1,057		194
Other income, net of expenses		63		130		(67	)		148		(18	)
Minority interest expense		27		48		(21	)		35		13
EBIT	$	1,329	$	1,333	$	(4	)	$	1,170	$	163
Proportional throughput, TBtu(a)		3,332		3,362		(30	)		3,160		202

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

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $175 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 $62 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses.

• A $40 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• A $95 million decrease as a result of the sale of Empire State Pipeline in February 2003 and Pacific Natural Gas (PNG) in December 2003, and

• An $80 million decrease in gas distribution revenues at Union Gas resulting from lower gas usage in the power market due to unfavorable weather.

Operating Expenses. The increase was driven primarily by:

• A $127 million increase caused by foreign exchange impacts (offset by currency impacts to revenues)

• A $62 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $52 million increase resulting from the favorable resolution in 2003 of various contingencies primarily related to a capital project and outstanding ad valorem and franchise tax issues from prior state audits

• A $17 million increase associated with the pipeline expansion projects placed in service

• A $14 million increase in depreciation primarily due to an increase in the depreciation rate and the addition of two major projects in the Western Canadian operations, partially offset by

• An $80 million decrease as a result of operations sold in 2003 as discussed above

• A $63 million decrease in the cost of gas sold for distribution at Union Gas, due primarily to reduced volumes

• A $29 million decrease due to severance costs in 2003, and

• A $23 million decrease primarily related to the 2004 resolution of ad valorem tax issues in various states.

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

• A $90 million decrease as a result of prior year gains on sales, primarily the gain on the sale of Natural Gas Transmission’s interests in Northern Border Partners L.P. in January 2003, Alliance Pipeline and the Aux Sable liquids plants in April 2003, and Foothills Pipe Lines Ltd in August 2003

• A $22 million decrease AFUDC (equity component) due to lower capital spending in 2004

• An $18 million decrease in equity earnings as a result of investments sold in 2003, partially offset by

• A $36 million increase resulting from the 2003 negative settlement of hedges related to foreign currency exposure

• An increase of $16 million in equity earnings of Gulfstream Natural Gas System, LLC, resulting from higher revenues and volumes due to fuel switching during the unusually active hurricane season in Florida in 2004, and

• A $16 million increase from 2004 gains on the sale of equity investments, primarily due to resolution of contingencies related to prior year sales.

Minority Interest Expenses. The decrease was driven primarily by the sale of PNG in December 2003, as well as lower earnings on Maritimes & Northeast Pipeline.

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EBIT. EBIT decreased primarily as a result of gains from sales of equity investments recorded in the prior year and foregone earnings from the investments sold. Those decreases were mostly offset by earnings from expansion projects and foreign exchange EBIT impacts from the strengthening Canadian currency.

Matters Impacting Future Natural Gas Transmission Results

Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Natural Gas Transmission expects modest annual EBIT growth over the next three years from its 2004 EBIT, generally consistent with growth in demand. Demand for natural gas is expected to grow two to three percent in DEGT’s key markets. The average contract life for the U.S. pipelines is eight years. Changes in the Canadian dollar, weather, throughput and the ability to renew service contracts would impact future financial results at Natural Gas Transmission.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. As part of this transaction, Natural Gas Transmission expects to receive assets in Alberta, Canada from ConocoPhillips. This transaction, which is subject to customary U.S. and Canadian regulatory approval, is expected to close in the latter half of 2005.

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. This increase was driven primarily by:

• A $466 million increase in transportation, storage and distribution revenue in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”)

• A $182 million increase due to foreign exchange favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• An $81 million increase from recovery of natural gas commodity costs that are passed through to customers without a mark-up at Union Gas. This amount is offset by a corresponding increase in expenses.

• A $31 million increase from completed and operational business expansion projects in the U.S., partially offset by

• A $58 million decrease from operations sold in 2003 and the fourth quarter of 2002.

Operating Expenses. This increase was driven primarily by:

• A $319 million increase in transportation, storage, and distribution expenses in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002

• A $135 million increase caused by foreign exchange impacts (partially offset by currency impacts to revenues)

• An $81 million increase related to increased natural gas prices at Union Gas. This amount is offset by a corresponding increase in revenues.

• A $20 million increase from 2003 severance charges related to workforce reductions, partially offset by

• A $38 million decrease from operations sold in the fourth quarter of 2002 and in 2003.

For the year ended December 31, 2003, Natural Gas Transmission’s operating expenses increased approximately 39% when compared to the same period in 2002, while operating revenues increased approximately 30%. The difference was due to the Westcoast operations that were acquired in March 2002. The operating expenses, as a percentage of operating revenues, of the acquired Westcoast natural gas distribution business, are greater than the previously owned natural gas transmission business. Gas commodity costs related to the Westcoast distribution business are recovered from customers by increasing revenues by the amount of gas commodity costs expensed (i.e. flowed through to customers with no incremental profit).

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

• A $36 million decrease from negative foreign exchange impacts in 2003, due to the settlement of hedges related to foreign currency exposure

• A $33 million decrease in equity earnings associated with the sold investments

• A $28 million decrease due to a construction fee received in 2002 from an affiliate related to the successful completion of Gulfstream, 50% owned by Duke Energy which went into service in May 2002, partially offset by

• A $58 million increase in gains from the sale of various equity investments in 2003, and

• A $17 million increase in AFUDC related to additional capital projects.

Minority Interest Expense. Minority interest expense increased in 2003 compared to 2002. This resulted from the recognition of a full year of minority interest expense in 2003, versus only ten months during 2002, from less than wholly owned subsidiaries acquired in the March 2002 acquisition of Westcoast.

EBIT. EBIT increased in 2003 compared to 2002, due primarily to incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast, gains on asset sales, and business expansion projects in the U.S. These items were partially offset by earnings in 2002 from operations that were sold in the fourth quarter of 2002 and during 2003, and 2003 severance charges in excess of 2002 amounts.

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Field Services

	Years Ended December 31,
	2004		2003			Variance 2004 vs 2003			2002		Variance 2003 vs 2002
	(in millions)
Operating revenues	$	10,044	$	8,538		$	1,506		$	5,910	$	2,628
Operating expenses		9,489		8,320			1,169			5,788		2,532
Gains (Losses) on sales of other assets, net		2		(4	)		6			—		(4	)
Operating income		557		214			343			122		92
Other income, net of expenses		38		68			(30	)		60		8
Minority interest expense		227		106			121			43		63
EBIT	$	368	$	176		$	192		$	139	$	37
Natural gas gathered and processed/transported, TBtu/d(a)		6.8		7.0			(0.2	)		7.5		(0.5	)
NGL production, MBbl/d(b)		356		346			10			372		(26	)
Average natural gas price per MMBtu(c)	$	6.14	$	5.39		$	0.75		$	3.22	$	2.17
Average NGL price per gallon(d)	$	0.68	$	0.53		$	0.15		$	0.38	$	0.15

(a) Trillion British thermal units per day

(b) Thousand barrels per day

(c) Million British thermal units

(d) Does not reflect results of commodity hedges

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was primarily driven by:

• A $870 million increase due primarily to a $0.15 per gallon increase in average NGL prices

• A $590 million increase due primarily to a $0.75 per MMBtu increase in average natural gas prices

• A $51 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing price volatility

• A $45 million increase attributable to a $10.29 per barrel increase in average condensate prices to $41.37 during 2004 from $31.08 during 2003

• A $30 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts, partially offset by

• A $44 million decrease related to the impact of cash flow hedging, which reduced revenues by approximately $242 million for the year ended December 31, 2004 and by $198 million for the year ended December 31, 2003, as compared to what revenue would have been without any hedging, and

• A $30 million decrease related to lower NGL and raw natural gas sales volume, partially offset by an increase in wholesale propane marketing activity primarily due to higher propane prices, and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips (“COP Acquisition”). Although production volumes increased as a result of processing economics and the COP Acquisition, sales volumes decreased as a result of producers marketing their NGLs on their own behalf.

Operating Expenses. The increase was driven primarily by:

• A $1,175 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices

• A $18 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets

• A $20 million increase related primarily to an increase in wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips partially offset by lower purchased raw natural gas supply volume, partially offset by

• A $25 million decrease in operating, and general and administrative expenses, primarily due to severance charges and other employee related expenditures in 2003 not experienced in 2004, lower repairs and maintenance, and environmental expenses in 2004, partially offset by an increase related to Field Services’ Sarbanes-Oxley compliance costs.

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

• A $23 million decrease due to impairment charges in 2004 related to management’s assessment of the recoverability of certain equity method investments

• A $13 million decrease due to the gains on sales of equity method investments in 2003, partially offset by

• A $7 million increase in equity earnings primarily due to increased earnings from equity method investments.

Minority Interest Expense. Minority interest expense increased in 2004 compared to 2003 due to increased earnings from DEFS, Duke Energy’s joint venture with ConocoPhillips. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT in 2004 compared to 2003 resulted primarily from the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

Matters Impacting Future Field Services Results

Field Services has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on operational excellence and organic growth. Field Services’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. Field Services anticipates that current price levels will continue to stimulate drilling and help to offset declining raw natural gas supplies. Although the prevailing price of natural gas has less short term significance to its operating results than the price of NGLs, in the long term, the growth and sustainability of Field Services’ business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7 percent interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. In connection with this transaction, DEFS expects to receive cash from ConocoPhillips. Upon completion of this transaction, DEFS will be owned 50 percent by Duke Energy and 50 percent by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approval, is expected to close in the latter half of 2005. This transaction is estimated to result in a pretax gain to Field Services of approximately $600 million. Additionally, in February 2005, DEFS sold its general partnership in TEPPCO for approximately $1.1 billion and Duke Energy sold its limited partnership interest in TEPPCO for approximately $100 million to Enterprise GP Holdings L.P. (EPCO), an unrelated third party. These transactions closed in the first quarter of 2005 and are estimated to result in a pretax gain to Field Services of approximately $900 million (net of approximately $330 million of minority interest).

As a result, Duke Energy expects to deconsolidate its investment in DEFS subsequent to the closing of the sale of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Energy has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Energy related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of the discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in Accumulated Other Comprehensive Income (AOCI) related to these contracts have been charged against earnings by Duke Energy in the first quarter of 2005, which will impact Field Services’ segment EBIT. On a prospective basis, these contracts will be accounted for under the MTM Model, which will impact Other EBIT.

Future revenues, gas purchases and EBIT will continue to be sensitive to commodity prices that have historically been cyclical and volatile. Field Services equity NGL position for 2005 was approximately 64% hedged as of December 31, 2004 at an average crude price equivalent of $38 per barrel. After considering the impacts of hedging, Field Services exposure to a one cent per gallon change in the average price of NGLs is $5 million for 2005. This figure does not include the effects of discontinued hedge accounting for certain 2005 and 2006 contracts, previously accounted for as cash flow hedges. During the first quarter of 2005, these contracts began to be accounted for under the MTM Model and, as a result, Duke Energy’s earnings for 2005 and 2006 will be subject to more volatility.

Field Services’ operating, and general and administrative costs are expected to increase in 2005, primarily due to asset integrity work and financial process improvements planned during the year. This increase is not expected to have a material effect on Field Services’ facility operating costs in 2005.

There are many important factors that could cause actual results to differ materially from the expectations expressed. Management can provide no assurances regarding the impact of future commodity prices or drilling activity.

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Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The increase was driven primarily by:

• A $2,200 million increase due primarily to a $2.17 per MMBtu increase in average natural gas prices

• A $1,180 million increase due primarily to a $0.15 per gallon increase in average NGL prices, partially offset by

• A $120 million decrease related to lower throughput of raw natural gas supply

• A $395 million decrease related to lower NGL production, and

• A $179 million decrease due to the impacts of cash flow hedging which reduced revenues by approximately $198 million for the year ended December 31, 2003 and by $19 million for the year ended December 31, 2002, as compared to what revenue would have been without any hedging.

Operating Expenses. The increase was primarily driven by:

• A $2,920 million increase due to higher costs of raw natural gas and NGL supply

• A $37 million increase related to other factors, including severance charges in 2003 and other employee related expenditures, partially offset by

• A $455 million decrease due to lower throughput volumes, and

• A $53 million decrease in 2003 operating expenses was due to 2002 charges related to Field Services internal review of balance sheet accounts ($37 million at Duke Energy’s 70% share), which may be related to corrections of accounting errors in periods prior to 2002. These adjustments were made in the following five categories: operating expense accruals; gas inventory valuations; gas imbalances; joint venture and investment account reconciliations; and other balance sheet accounts and were immaterial to Duke Energy’s reported results.

Minority Interest Expense. Minority interest expense at Field Services increased in 2003 compared to 2002 due to increased earnings from DEFS. The increase in minority interest expense was not proportionate to the increase in Field Services’ earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS results.

EBIT. EBIT for 2003 increased compared to 2002 as a result of better pricing and other factors discussed above.

DENA

	Years Ended December 31,
	2004			2003			Variance 2004 vs 2003			2002			Variance 2003 vs 2002
	(in millions)
Operating revenues	$	173		$	167		$	6		$	376		$	(209	)
Operating expenses		368			1,938			(1,570	)		564			1,374
Losses on sales of other assets, net		(427	)		(208	)		(219	)		—			(208	)
Operating (loss) income		(622	)		(1,979	)		1,357			(188	)		(1,791	)
Other income, net of expenses		12			197			(185	)		67			130
Minority interest benefit		(25	)		(106	)		81			(46	)		(60	)
EBIT	$	(585	)	$	(1,676	)	$	1,091		$	(75	)	$	(1,601	)
Actual plant production, GWh(a)(b)		3,343			6,084			(2,741	)		5,685			399
Net proportional megawatt capacity in operation(b)		3,600			9,085			(5,485	)		7,223			1,862

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

(b) Excludes discontinued operations

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by a $10 million increase in power generation revenues, due primarily to increased average power prices, partially offset by lower volumes due to the sale of the Southeast Plants in the second quarter of 2004.

Operating Expenses. The decrease was driven primarily by:

• A $1,420 million decrease in asset impairments and other related charges, including a $1,166 million asset impairment charge recognized in 2003 primarily in connection with DENA’s exit from the Southeast region, the related discontinuance of Southeast region hedges, and a goodwill impairment charge recognized in 2003 related to the trading and marketing business of $254 million

• A $147 million decrease in general and administrative expenses, primarily due to the impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower bad debt expense. A 2003

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$28 million Commodity Futures Trading Commission (CFTC) settlement ($17 million net of minority interest expense) and 2003 severance costs of $10 million also contributed to a favorable variance in general and administrative expenses

• A $58 million decrease in depreciation expense, primarily due to the sale of the Southeast Plants

• A $21 million decrease in operations and maintenance expense, due primarily to the sale of the Southeast Plants and reduced costs from renegotiated outsourcing agreements, partially offset by two plants entering into commercial operation late in the second quarter of 2003, partially offset by

• A $75 million increase in plant fuel costs due primarily to higher average gas prices, and offset by lower volumes as a result of the sale of the Southeast Plants.

Losses on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the sale of DENA’s Southeast Plants and approximately $65 million of pre-tax losses associated with the sales and terminations of DETM contracts. Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million pre-tax loss on the sale of the 25% net interest in the Vermillion facility, a $66 million pre-tax loss on the sale of turbines and $127 million of DETM pre-tax charges related to the sale of contracts.

Other Income, net of expenses. The decrease in other income, net of expenses was due primarily to the $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Ref-Fuel and the associated foregone equity earnings of $22 million.

Minority Interest Benefit. Minority interest benefit decreased due primarily to more favorable 2004 results at DETM as compared to 2003 as a result of the DETM wind-down of operations.

EBIT. EBIT increased primarily as a result of the decreased losses from impairments and other related charges, lower plant depreciation and operating expenses from the 2004 sale of the Southeast Plants and lower general and administrative expense. These increases were partially offset by losses on sales of assets, as outlined above.

Matters Impacting Future DENA Results

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

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The decrease was driven primarily by:

• A $61 million decrease in net trading margin from the wind down of DETM, and

• A $148 million reduction in overall power revenues, due primarily to lower average power prices.

Operating Expenses and Impairments. The increase was driven primarily by:

• A $1,264 million increase due to asset impairments and other related charges related to current market conditions and strategic actions taken by management. For 2003 these net charges totaled $1,420 million and related to a $1,166 million asset impairment charge in connection with DENA’s Southeast Plants, discontinuance of Southeast region hedges, and a goodwill impairment charge related to the trading and marketing business of $254 million. These amounts were offset by $156 million of charges taken in 2002 comprised of provisions for the termination of certain turbines on order and the write-down of other uninstalled turbines of $121 million, the write-off of site development costs of $11 million, and a charge of $24 million for the write-off of an information technology system.

• A $12 million increase in overall gas costs due primarily to higher average gas prices and increased volumes from projects that entered into commercial operation during 2002 and 2003

• An $84 million increase in other plant related operations, maintenance, and depreciation due primarily to increased costs associated with projects that entered into commercial operation during 2002 and 2003, and

• A $16 million increase in other general and administrative expenses due primarily to a CFTC settlement in 2003 of $28 million ($17 million at Duke Energy’s 60% share).

Losses on Sales of Other Assets, net. Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million loss on the sale of the 25% net interest in the Vermillion facility, a $66 million loss on the sale of turbines and DETM charges related to the sale of contracts of $127 million.

Other Income, net of expenses. The increase in other income, net of expenses was due primarily to the $178 million pre-tax gain in 2003 from the sale of DENA’s 50% ownership interest in Ref-Fuel, slightly offset by the associated foregone equity earnings of $22 million.

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Minority Interest Benefit. Minority interest benefit increased in 2003 compared to 2002, due to increased losses at DETM.

EBIT. EBIT for 2003 decreased compared to 2002. The decrease was due primarily to those factors discussed above: plant impairments, disqualification of certain hedges, the wind down of DETM, and the write-off of goodwill.

International Energy

	Years Ended December 31,
	2004			2003		Variance 2004 vs 2003			2002		Variance 2003 vs 2002
	(in millions)
Operating revenues	$	619		$	597	$	22		$	743	$	(146	)
Operating expenses		462			426		36			716		(290	)
Losses on sales of other assets, net		(3	)		—		(3	)		—		—
Operating income		154			171		(17	)		27		144
Other income, net of expenses		78			57		21			85		(28	)
Minority interest expense		10			13		(3	)		10		3
EBIT	$	222			215		7			102		113
Sales, GWh		17,776			16,374		1,402			18,350		(1,976	)
Net proportional megawatt capacity in operation(a)		4,139			4,121		18			3,917		204

(a) Excludes discontinued operations

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $32 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala

• A $22 million increase in volumes due to higher electricity dispatch in Ecuador as a result of unplanned outages at competing generators

• A $20 million increase in Brazil resulting from higher contracted sales prices of $26 million which were positively impacted by inflation adjustments primarily offset by the impact of a 2003 regulatory audit revenue adjustment

• A $12 million increase due to higher electricity prices caused by low water availability in Peru

• A $12 million increase due to favorable exchange rates primarily in Brazil, partially offset by

• A $48 million decrease in Guatemala and El Salvador due to decreased cross border power marketing activity resulting from unfavorable market conditions, and

• A $33 million decrease in natural gas sales due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003.

Operating Expenses. The increase was driven primarily by:

• A $23 million increase due to the fourth quarter 2003 completion of the 160 megawatt (MW) Planta Arizona expansion in Guatemala as discussed above

• A $21 million increase in electricity generation costs resulting from higher levels of dispatch in Ecuador as described above

• An $18 million increase due to a reserve reduction in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business

• A $17 million increase in Peru power purchases to satisfy sale contract requirements caused by decreased generation as a result of low water availability

• A $14 million increase due to general and administrative expenses primarily due to higher corporate allocations and Sarbanes-Oxley compliance costs

• A $12 million increase in Brazil due primarily to increased transmission fees and other costs offset by an environmental charge recorded in 2003 and a reduction in the environmental reserves in 2004, partially offset by

• A $42 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity

• A $37 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the LNG business in 2003 and

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• A $13 million charge associated with the disposition of the ownership share in the Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) nitrogen facility in Mexico.

Other Income, net of expenses. The increase was primarily the result of:

• An $11 million increase due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment, and

• A $6 million increase due to favorable netback pricing at National Methanol Company

EBIT. EBIT increased modestly in 2004 compared to 2003. The slight increase was due to the factors described above.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio.

EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.

During 2005, Duke Energy’s Brazilian affiliate may participate in the next regulated auction for the sale of power to the distribution companies. The auction process provides for 8 year contracts with delivery commencing in 2008 and 2009. The outcome of these auctions could impact International Energy’s EBIT results for the years 2008 and beyond.

International Energy owns a 50% joint venture interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche). Campeche operates a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. Campeche has made a renewal offer to PEMEX that has been initially rejected; however, discussions continue with PEMEX regarding renewal of the contract or other possible arrangements. If it is determined that the renewal will not take place or another economically viable arrangement is not found, the value of International Energy’s equity investment in Campeche would decline and such investment would be written down to its resulting fair value. International Energy’s estimated maximum exposure to this risk is potential impairment or other charges of $70 million.

Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt. In general, interest rates were lower in 2004 than in 2003 and the resulting impact on contract revenues and interest expense in 2004 was not as great as in 2003.

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The decrease was driven primarily by:

• A $91 million nonrecurring favorable impact on 2002 revenues as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating expenses

• A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million revenue reduction, which is offset in expense

• Lower revenues of $35 million in El Salvador as a result of a power sales contract not being renewed by a counterparty

• Lower LNG sales of $33 million, due primarily to the termination of a gas sales contract

• Unfavorable exchange rate impacts resulting in a decrease of $10 million in Brazil and Argentina, partially offset by

• An increase of $35 million related primarily to favorable recontracting terms on electricity sales contracts in Brazil

• An increase of $25 million as a result of the completion of the 160 MW expansion in Guatemala, and

• Increases to revenues and receivables for adjustments of $11 million as a result of a regulatory audit in Brazil.

Operating Expenses. The decrease was driven primarily by:

• A $91 million nonrecurring favorable impact on 2002 operating expenses as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating revenues

• A $75 million write-down in 2002 for the cancellation of capital projects in Brazil and Bolivia

• A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million expense reduction, which is offset in revenue

• A $26 million charge and reserve for environmental settlements in Brazil

• Lower expenses in the LNG business due to a $40 million charge recorded in 2002 for estimated probable losses due the early termination of a natural gas sales contract and $31 million in lower gas purchases

• Lower expenses of $19 million in El Salvador as a result of reduced contract sales volumes

• Cost savings of $17 million from lower International Energy corporate expenses, partially offset by

• Higher operating expenses of $22 million due to the completion of the 160 MW expansion in Guatemala.

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Other Income, net of expenses. The decrease was primarily the result of:

• A $43 million decrease in equity investment income in Mexico due to a change in revenue recognition, increased repair costs, lower revenue due to downtime, and currency translation, partially offset by

• An $11 million increase in equity investment income at National Methanol Company due to favorable product prices.

EBIT. The increase was due primarily to the absence of $75 million in charges for project cancellations that occurred in 2002, favorable contract terms on the renewal of the initial contracts in Brazil, and increased volumes in Central America due to the completion of expansion projects. Other principal drivers included net increases of $40 million from the LNG business, $17 million due to lower administrative expenses, and $11 million on the equity investment income for National Methanol Company, offset by changes in revenue recognition and operating results in Mexico, as noted above.

Crescent

	Years Ended December 31,
	2004			2003		Variance 2004 vs 2003			2002			Variance 2003 vs 2002
	(in millions)
Operating revenues	$	437		$	284	$	153		$	226		$	58
Operating expenses		393			231		162			177			54
Gains on sales of investments in commercial and multi-family real estate		192			84		108			106			(22	)
Operating income		236			137		99			155			(18	)
Other income, net of expenses		3			—		3			1			(1	)
Minority interest (benefit) expense		(1	)		3		(4	)		(2	)		5
EBIT	$	240		$	134	$	106		$	158		$	(24	)

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by a $160 million increase in residential developed lot sales, due to increased sales at the LandMar division in northeastern and central Florida, the Palmetto Bluff project in Bluffton, South Carolina, The Sanctuary project near Charlotte, North Carolina, the Lake James projects in northwestern North Carolina and the Lake Keowee projects in northwestern South Carolina.

Operating Expenses. The increase was driven primarily by a $101 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above, $50 million in impairments and other related charges (net of $12 million minority interest as discussed below) related to Twin Creeks, Texas and Payson, Arizona residential development projects and a $26 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. (See Note 12 to the Consolidated Financial Statements, “Impairments, Severance, and Other Related Charges” for further discussion of Crescent’s impairments.)

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

• A $31 million increase in commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March 2004

• A $63 million increase in real estate land sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area in 2004, and

• A $16 million increase in land management or “legacy” land sales, due to several large sales closed in the first quarter of 2004.

Minority Interest (Benefit) Expense. The increase in minority interest benefit is primarily due to $12 million of benefit related to impairment and bad debt charges at the Payson, Arizona project as noted above offset by an additional $8 million in minority interest expense related to increased earnings from the LandMar division.

EBIT. As discussed above, the increase in EBIT was driven primarily by an increase in residential developed lot sales and commercial project sales, the sale of the Washington, D.C. area land tracts and an increase in “legacy” land sales.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, DC area which resulted in higher than normal gains during 2004. Crescent expects segment EBIT from continuing operations and discontinued operations to return to a more normal level of approximately $150 million in 2005. When property management or other significant accounting involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

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Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The increase was driven primarily by increased revenues of $69 million from residential developed lot sales offset by a $5 million decrease in commercial rents. Residential developed lot sales increased in 2003 primarily due to sales at the Palmetto Bluff project in Bluffton, South Carolina of $51 million and increased sales in an existing project in Florida of $28 million. The decrease in commercial rents was due to a smaller portfolio of commercial properties in 2003 as a result of decreased development activities in the commercial sector.

Operating Expenses. The cost of residential developed lot sales increased $50 million as a result of increased sales as discussed above.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was due to a $40 million decrease in legacy land sales offset by a $17 million increase in commercial land sales. The decrease in legacy land sales was due to a declining inventory of large, contiguous tracts in North and South Carolina, as well as a decrease in demand by large tract purchasers. The increase in commercial land sales was due to the initial sales of land at our Potomac Yard project in the Washington, DC area.

EBIT. The decrease was primarily the result of decreased land management sales partially offset by increased earnings from commercial land sales and residential developed lot sales.

Other

	Years Ended December 31,
	2004			2003			Variance 2004 vs 2003			2002			Variance 2003 vs 2002
	(in millions)
Operating revenues	$	1,144		$	1,628		$	(484	)	$	303		$	1,325
Operating expenses		1,257			1,933			(676	)		655			1,278
Gains on sales of other assets, net		4			—			4			32			(32	)
Operating income		(109	)		(305	)		196			(320	)		15
Other income, net of expenses		32			33			(1	)		(48	)		81
EBIT	$	(77	)	$	(272	)	$	195		$	(368	)	$	96

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. Operating revenues for 2004 decreased $484 million, compared to 2003. The decrease was driven primarily by a $337 million decrease in revenues related to decreased sales volumes as a result of the continued wind-down of DEM and a $162 million decrease due to the sale of Energy Delivery Services (EDS) in December 2003.

Operating Expenses. The decrease was driven primarily by:

• A $140 million decrease due primarily to a $51 million write-off in 2003 related to a corporate risk management information system that was abandoned, lower governance costs in 2004 due to cost reductions and allocation of certain costs previously designated as corporate to business units, and severance costs in 2003

• A $555 million decrease as a result of the continued wind-down of DEM and the sale of EDS in December 2003

• A $64 million decrease in 2004 as a result of the correction of an accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Energy subsidiaries

• A $21 million gain related to the settlement of the Enron bankruptcy proceedings in April 2004, and

• A $17 million decrease in general and administrative expense due to lower activity as a result of the decision in 2003 to exit the areas of refined products and NGLs at DEM. In addition, the absence of 2003 losses of $32 million from adverse market movements against some commodity positions positively affected the overall year over year increase.

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

EBIT. EBIT increased in 2004 compared to 2003. The increase in EBIT was primarily driven by the wind-down of DEM, the reversal of insurance reserves at Bison, and other reductions in operating expense.

Matters Impacting Future Other Results

Other is expected to remain mostly comprised of certain unallocated corporate costs, DukeNet, D/FD, and Bison. DEM continues to wind-down its position in ammonia, coal, hydrocarbon and refined products. D/FD will continue to decrease its earnings as the partnership winds down by the end of 2005.

Duke Energy expects to deconsolidate its investment in DEFS subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Energy has discontinued hedge accounting for certain 2005

24

and 2006 contracts held by Duke Energy related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in AOCI related to these contracts have been reclassified into earnings by Duke Energy in the first quarter of 2005, which will impact Field Services’ segment EBIT. On a prospective basis, these contracts will be accounted for under the MTM Model, which will impact Other EBIT. As a result of these contracts being accounted for under the MTM Model, future earnings for Other in 2005 and 2006 will be subject to increased volatility.

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment.

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues. The increase was driven primarily by:

• A $1,300 million increase at DEM in connection with the January 1, 2003 adoption of the final consensus on EITF Issue No. 02-03. See earlier discussion under “Consolidated Operating Revenues”

• A $70 million increase in revenues at EDS, as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003, partially offset by

• A $172 million decrease due to the sale of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) in 2002.

Operating Expenses. The increase was driven primarily by:

• A $1,300 million increase at DEM, due primarily to the adoption of the final consensus on EITF Issue No. 02-03

• A $72 million increase at EDS, as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003.

• A $51 million increase for a 2003 write-off related to a corporate risk management information system that was abandoned, partially offset by

• A $164 million decrease due to the sale of DE&S and DukeSolutions in 2002, and

• A $21 million decrease in DEM’s general and administrative costs due to the wind-down of its business.

Gains on Sales of Other Assets, net. Gains on sales of other assets decreased in 2003 compared to 2002 due primarily to a 2002 net gain of $33 million on the sale of Duke Energy’s remaining water operations.

Other Income, net of expenses. Other income, net of expenses increased in 2003, compared to 2002, due primarily to increased earnings related to D/FD.

EBIT. EBIT increased in 2003 compared to 2002. The increase in EBIT was primarily driven by the increase in other income, offset by the decrease due to the sale of assets.

Other Impacts on Earnings Available for Common Stockholders

Interest expense decreased $49 million in 2004 compared to 2003. The decrease was due primarily to:

• A $131 million decrease from net debt reduction and refinancing activities

• A $16 million write-off in 2003 as a result of an order by the PSCSC to write off regulatory assets related to debt issuance costs through interest expense, partially offset by

• $40 million of lower capitalized interest due to decreased construction activity

• $26 million of expenses related to financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”

• A $20 million increase associated with Canadian exchange rates, and

• $17 million higher interest costs in Brazil, due to Duke Energy’s Brazilian debt being indexed annually to inflation and unfavorable impact of exchange rates.

Duke Energy anticipates interest expense to be approximately $1.1 billion in 2005. The projected reduction in interest expense from 2004 reflects the impact of Duke Energy’s net debt reductions in 2004.

Interest expense increased $214 million in 2003 as compared to 2002. The increase was due primarily to:

• $82 million decrease in capitalized interest, resulting from lower plant construction activity in 2003

• $48 million of expenses related to certain financial instruments with characteristics of both liabilities and equity whose related distributions were classified as interest expense in 2003 instead of minority interest expense, and

• $84 million remaining increase was due primarily to higher debt balances, resulting mainly from debt assumed in, and issued with respect to, the acquisition of Westcoast, slightly offset by lower borrowing costs.

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Minority interest expense increased $138 million in 2004 as compared to 2003, and decreased $29 million in 2003 as compared to 2002. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Energy and its subsidiaries. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No. 150. As a result of this accounting change, minority interest expense decreased $55 million for 2004 and $75 million for 2003.

Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of Duke Energy’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures. Total minority interest expense related to the joint ventures (including the portion related to interest and taxes) increased $193 million in 2004 as compared to 2003, and increased $46 million in 2003 as compared to 2002. The 2004 change was driven by increased earnings at Field Services and improved results at DENA as a result of the continued wind-down of DETM. The 2003 change was driven by increased earnings at DEFS, and Natural Gas Transmission, offset by decreased earnings at DETM.

Income tax expense increased $627 million for the year ended December 31, 2004, compared to the same period in 2003, due primarily to the $1,808 million increase in earnings from continuing operations and the $45 million taxes recorded in 2004 on the repatriation of foreign earnings that is expected to occur in 2005 associated with the American Jobs Creation Act of 2004. These increases were partially offset by the $52 million reduction of state and federal income tax reserves and the $20 million of tax benefit from the change in state tax rates related to deferred taxes as a result of a reorganization of certain subsidiaries in 2004. Income tax expense decreased $608 million in 2003, compared to 2002, due primarily to the large impairment charges recorded in 2003. (See Note 6 to the Consolidated Financial Statements, “Income Taxes,” for additional information.)

Income (loss) from discontinued operations was $238 million for 2004, ($1,232) million for 2003, and ($111) million for 2002. These amounts represent results of operations and gains (losses) on dispositions related primarily to International Energy’s Asia-Pacific Business and European Business, Duke Capital Partners, LLC (DCP), Field Services, DENA, Crescent and DEM. (See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.”)

The 2004 amount is primarily comprised of a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, and an approximate $117 million after-tax gain on the sale of two partially constructed DENA plants offset by operating losses at DENA. DENA’s 2004 gain related to the settlement of the Enron bankruptcy proceedings was entirely offset by a charge related to the California and western U.S. energy markets settlement. The 2003 amount is primarily comprised of $1.7 billion in pre-tax impairment charges related to DENA’s partially completed Western plants, related forward power and gas contracts that were de-designated as normal purchases and sales and cash flow hedges, a generation plant in Maine and the Morro Bay plant in California. Also contributing to the 2003 amount was a $223 million after tax charge for International Energy’s impairment charges incurred as a result of classifying its Asia-Pacific assets as held for sale and exiting the European market. The 2002 amount is primarily comprised of $194 million pre-tax charge for the impairment of goodwill for International Energy’s European Business and $51 million of pre-tax charges at DENA to impair one of its merchant power facilities and write-off site development costs in California.

During 2003, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $151 million, or $0.17 per basic share, related to the implementation of EITF 02-03 and an after-tax charge of $11 million, or $0.01 per basic share, related to the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

In connection with the TEPPCO and DEFS transactions discussed above, Duke Energy has announced plans to periodically repurchase up to an aggregate $2.5 billion of common stock over the next three years.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to evolve as Duke Energy’s operations change and accounting guidance evolves. Duke Energy has identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.

Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Energy’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Energy discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy’s critical accounting policies and estimates are listed below.

Risk Management Accounting

Duke Energy uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations: the MTM Model and the Accrual Model. As further discussed in Note 1 to the Consolidated Financial Statements, the MTM Model is applied to trading and undesignated non-trading derivative contracts, and the Accrual Model is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. For the three years ended December 31, 2004, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the EITF. Effective January 1, 2003, Duke Energy adopted EITF Issue No. 02-03. While the implementation of such guidance changed the accounting model used for certain of Duke Energy’s transactions, especially non-derivative energy trading contracts, the overall application of the models remained the same.

Under the MTM Model, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations during the current period. While DENA is the primary business segment that uses this accounting model, the Franchised Electric, International Energy, and Field Services segments, as well as Other, also have certain transactions subject to this model. For the years ended December 31, 2004 and 2003, Duke Energy applied the MTM Model to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below). For the year ended December 31, 2002, Duke Energy also applied the MTM Model to energy trading contracts, as defined by EITF Issue No 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, which was superseded by EITF Issue No. 02-03.

The MTM Model is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. When available, quoted market prices are used to measure a contract’s fair value. However, market quotations for certain energy contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to the MTM Model, especially after implementation of EITF Issue No. 02-03 due to the discontinuation of the MTM Model for certain energy trading contracts, such as transportation agreements. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.

Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. However, due to the nature and number of variables involved in estimating fair values, and the interrelationships among these variables, sensitivity analysis of the changes in any individual variable is not considered to be relevant or meaningful.

Validation of a contract’s calculated fair value is performed by an internal group independent of Duke Energy’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

For certain derivative instruments Duke Energy applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the Accrual Model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).

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Hedge accounting treatment is used when Duke Energy contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when Duke Energy holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of a commodity, such as natural gas or electricity, may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Energy’s hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be recognized in the Consolidated Statements of Operations.

The normal purchases and normal sales exemption, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Energy’s case, the delivery of power). Previously, Duke Energy applied this exemption for certain contracts involving the sale of power in future periods. SFAS No. 149 includes certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity. As a result, Duke Energy reevaluated its policy for accounting for forward power sale contracts and determined that substantially all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either model.

In addition to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, the Accrual Model also encompasses non-derivative contracts used for commodity risk management purposes. For these non-derivative contracts, there is no recognition in the Consolidated Statements of Operations until the service is provided or delivery occurs.

For additional information regarding risk management activities, see Quantitative and Qualitative Disclosures about Market Risk. The Quantitative and Qualitative Disclosures about Market Risk include daily earnings at risk information related to commodity derivatives recorded using the MTM Model and an operating income sensitivity analysis related to hypothetical changes in certain commodity prices recorded using the Accrual Model.

Regulatory Accounting

Duke Energy accounts for certain of its regulated operations (primarily Franchised Electric and Natural Gas Transmission) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Total regulatory assets were $2,108 million as of December 31, 2004 and $2,016 million as of December 31, 2003. Total regulatory liabilities were $1,744 million as of December 31, 2004 and $1,788 million as of December 31, 2003. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)

Long-Lived Asset Impairments and Assets Held For Sale

Duke Energy evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, an impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.

Duke Energy uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power, natural gas or NGL, costs of fuel over periods of time consistent with the useful lives of the assets or changes in the real estate market. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time.

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A change in Duke Energy’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Energy considers various factors when determining if impairment tests are warranted, including but not limited to:

• Significant adverse changes in legal factors or in the business climate;

• A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;

• A significant change in the market value of an asset; and

• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144.

During 2004, Duke Energy recorded impairments on several of its long-lived assets. (For additional discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Impairment and Other Related Charges.”)

Duke Energy may dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2004. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Energy’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2004 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Energy could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.

Impairment of Goodwill

Duke Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of Duke Energy’s goodwill at December 31, 2004 relates to the acquisition of Westcoast in March 2002. The remainder relates to Field Services, International Energy’s Latin American operations and Crescent. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of general and administrative costs. In estimating cash flows, Duke Energy incorporates current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices. As a result of the 2004 impairment test required by SFAS No. 142, Duke Energy did not record any impairment on its goodwill. In the third quarter of 2003, Duke Energy recorded a $254 million goodwill impairment charge to write off all of DENA’s goodwill, most of which related to certain aspects of DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. In 2002, Duke Energy recorded a goodwill impairment charge of $194 million related to International Energy’s European Business, which was sold in 2003. Duke Energy used a discounted cash flow analysis utilizing the key assumptions described above to perform the analysis.

Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

As of the acquisition date, Duke Energy allocates goodwill to a reporting unit. Duke Energy defines a reporting unit as an operating segment or one level below.

Revenue Recognition

Unbilled and Estimated Revenues. Revenues on sales of electricity, primarily at Franchised Electric, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered but not billed. Differences between actuals and estimates are immaterial and are a result of customer mix.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.

Trading and Marketing Revenues. The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the Accrual Model or MTM Model is applied. Prior to January 1, 2003, Duke Energy applied the MTM Model to certain derivative contracts and certain contracts classified as energy trading

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pursuant to EITF Issue 98-10. With the implementation of EITF Issue 02-03, use of the MTM Model has been restricted to contracts classified as derivatives pursuant to SFAS No. 133. Contracts classified previously as energy trading that do not meet the definition of a derivative are subject to the Accrual Model. While the MTM Model is the default method of accounting for all SFAS No. 133 derivatives, SFAS No. 133 allows for the use of the Accrual Model for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Energy designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. (For further information regarding the Accrual Model or MTM Model, see Risk Management Accounting above. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.)

Pension and Other Post-Retirement Benefits

Duke Energy and its subsidiaries maintain a non-contributory defined benefit retirement plan. It covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Duke Energy and most of its subsidiaries also provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings. Westcoast also provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply to employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, “Employers’ Accounting for Pensions.” Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees’ approximate service periods. Other post-retirement benefits are accounted for using SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” (See Note 21 to the Consolidated Financial Statements, “Employee Benefit Plan”.)

Funding requirements for defined benefit plans are determined by government regulations, not SFAS No. 87. Duke Energy made voluntary contributions of $250 million in 2004 and $181 million in 2003 to its U.S. defined benefit retirement plan. No contributions to the Duke Energy plan were necessary in 2002. No contributions are expected for the U.S. plan in 2005. Duke Energy made contributions to the Westcoast DB plans of approximately $28 million in 2004, $11 million in 2003 and $9 million in 2002. Duke Energy anticipates that it will make contributions of approximately $33 million to the Westcoast DB plans in 2005. Duke Energy made contributions to the Westcoast DC plans of approximately $3 million in 2004, $3 million in 2003 and $2 million in 2002. Duke Energy anticipates that it will make contributions of approximately $3 million to the Westcoast DC plans in 2005.

The calculation of pension expense, other post-retirement expense and Duke Energy’s pension and other post-retirement liabilities require the use of assumptions. Changes in these assumptions can result in different expense and reported liability amounts, and future actual experience can differ from the assumptions. Duke Energy believes that the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate. Additionally, the health care trend rate assumption is critical for other post-retirement benefits.

Duke Energy recognized pre-tax pension income of $1 million and pre-tax other post-retirement benefits expense of $58 million in 2004. Westcoast recognized pre-tax pension expense of $14 million and pre-tax other post-retirement benefits expense of $8 million in 2004. In 2005, Duke Energy’s U.S. pension expense is expected to be approximately $23 million due to lower than expected asset returns from 2000 through 2002 being amortized into expense over a five year period elected as allowed under SFAS No. 87. Duke Energy’s other U.S. and Westcoast plans do not expect material changes from the expense of 2004.

For both pension and other post-retirement plans, Duke Energy assumed that its U.S. plan’s assets would generate a long-term rate of return of 8.5% as of September 30, 2004. The assets for Duke Energy’s U.S. pension and other post retirement plans are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate.

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The expected long-term rate of return of 8.5% for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non U.S. equities, 2.2% for fixed income securities, and 0.2% for real estate. A premium of 0.4% was added for the higher returns expected for the plan’s use of active asset managers.

If Duke Energy had used a long-term rate of 8.0% in 2004, pre-tax pension expense would have been approximately $14 million. If Duke Energy had used a long-term rate of 9.0% pre-tax pension income would have been higher by approximately $14 million. If Duke Energy had used a long-term rate of 8.0% in 2004, pre-tax other post-retirement expense would have been higher by approximately $1 million. If Duke Energy had used a long-term rate of 9.0% pre-tax other post retirement expense would have been lower by approximately $1 million.

The expected long-term rate of return for the Westcoast plans assets was 7.50% as of September 30, 2004. The Westcoast plans assets for registered pension plans are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The expected long-term rate of return of 7.50% for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 2.0% for Canadian equities, 1.9% for U.S. equities, 1.9% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities. If the Westcoast plan had used a long-term rate of 7.0% in 2004, pre-tax pension expense would have been higher by $2 million. If the Westcoast plans had used a long-term rate of 8.0% in 2004, pre-tax pension expense would have been lower by $2 million. The Westcoast other post-retirement plan does not hold any assets.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 6.00% as of September 30, 2004 and 2003, compared to 6.75% as of September 30, 2002. Duke Energy determines the appropriate discount based on the current rates earned on long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2004, the discount rate used to calculate pension and other post-retirement expense was 6.00%. Lowering the discount rate by 0.25% (from 6.00% to 5.75%) would have increased Duke Energy’s 2004 pre-tax pension income by approximately $3 million. Increasing the discount rate by 0.25% (from 6.00% to 6.25%) would have increased Duke Energy’s 2004 pre-tax pension expense by approximately $3 million. Lowering the discount rate by 0.25% (from 6.00% to 5.75%) would have increased Duke Energy’s 2004 pre-tax other post retirement expense by approximately $1 million. Increasing the discount rate by 0.25% (from 6.00% to 6.25%) would have decreased Duke Energy’s 2004 pre-tax other post retirement expense by approximately $1 million.

Westcoast discounted its future pension and other post-retirement obligations using a rate of 6.25% as of September 30, 2004 compared to 6.00% as of September 30, 2003 and 6.50% as of September 30, 2002. For Westcoast the discount rate used to determine the pension and other post-retirement obligations is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2004, the discount rate used to calculate pension expense was 6.00%. Lowering the discount rate by 0.25% (from 6.00% to 5.75%) would have increased Duke Energy’s 2004 pre-tax pension expense by approximately $2 million. Increasing the discount rate by 0.25 % (from 6.00% to 6.25%) would have decreased Duke Energy’s 2004 pre-tax pension expense by approximately $2 million. Lowering the discount rate by 0.25% (from 6.00% to 5.75%) would have increased Duke Energy’s 2004 pre-tax other post-retirement expense by less than $1 million. Increasing the discount rate by 0.25 % (from 6.00% to 6.25%) would have decreased Duke Energy’s 2004 pre-tax other post-retirement expense by less than $1 million.

Duke Energy’s U.S. post-retirement plan uses a health care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2004, the health care trend rates were 9.50%, which grades to 6.00% by 2009 for employees who are not eligible for Medicare and 12.5%, which grades to 6.00% by 2012 for employees who are eligible for Medicare. If Duke Energy had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by $3 million. If Duke Energy had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by $3 million.

The Westcoast post-retirement plans use a health care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2004, the health care trend rates were 9.00%, which grades to 5.00% by 2008. If Duke Energy had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by $1 million. If Duke Energy had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by less than $1 million.

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Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future.

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

Duke Energy will rely primarily upon cash flows from operations and borrowings to fund its liquidity and capital requirements for 2005. Also, Duke Energy expects cash flows from asset sales related to Duke Energy transferring a 19.7% interest in DEFS to ConocoPhillips as well as the sale by Field Services of TEPPCO and Duke Energy’s sale of its limited partner interests in TEPPCO Partners L.P., as discussed below. The net cash from these transactions along with current cash, cash equivalents and short-term investment balances of approximately $1.9 billion and future cash generated from operations may be utilized by Duke Energy to periodically repurchase up to an aggregate of $2.5 billion of common stock over the next three years. A material adverse change in operations or available financing may impact Duke Energy’s ability to fund its current liquidity and capital resource requirements. The relatively stable operating cash flows of the Franchised Electric and Natural Gas Transmission businesses currently compose a substantial portion of Duke Energy’s cash flow from operations and it is anticipated that they will continue to do so for the next several years.

Duke Energy currently anticipates net cash provided by operating activities in 2005 to be approximately $2.7 billion, including approximately $300 million of residential real estate capital expenditures. Net cash provided by operating activities in 2005 assumes a mid-year closing of the sale of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips, resulting in a change to equity method accounting treatment for Duke Energy’s remaining ownership interest in DEFS as any future cash distributions from DEFS to Duke Energy, subsequent to the closing of the sale transaction, will be included in operating activities in the Consolidated Statements of Cash Flows. Anticipated cash provided by operating activities for 2005 includes the impact of realizing approximately $450 million of net operating losses, which resulted principally from the carryover of unutilized 2004 income tax losses from the sale of DENA’s Southeast Plants and the partially completed Moapa and Luna plants in 2004. Achievement of these projected amounts is subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, and market volatility.

Duke Energy projects 2005 capital and investment expenditures of approximately $2.5 billion, including approximately $300 million of residential real estate capital expenditures. Duke Energy continues to focus on reducing risk and restructuring its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 70% of total projected 2005 capital expenditures are projected to be allocated to Natural Gas Transmission and Franchised Electric. Total projected capital and investment expenditures include approximately $1.4 billion for maintenance and upgrades of existing plants, pipelines, and infrastructure to serve load growth. Additionally, Duke Energy anticipates approximately $470 million in capital and investment expenditures for Crescent, including $300 million of residential real estate capital expenditures. Expenditures at Crescent and Natural Gas Transmission constitute the majority of the expansion capital planned in 2005 by Duke Energy. Duke Energy is also focused on pursuing various options to create a sustainable business model at DENA, including consideration of potential business partners. See earlier discussion in Introduction section for more information. See also Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions closed in the first quarter of 2005 and are estimated to result in a pretax gain to Duke Energy of approximately $900 million (net of approximately $330 million of minority interest).

Additionally, in February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. The consideration is expected to consist of the current Canadian operations of DEFS, the transfer of certain Canadian assets from ConocoPhillips to Duke Energy and the transfer of certain U.S. Midstream assets, or cash, from ConocoPhillips to DEFS, and the payment of cash from ConocoPhillips to Duke Energy of at least $500 million. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005.

As a result of the transactions discussed above, Duke Energy anticipates its debt to total capitalization ratio to be below 50% by the end of 2005.

In 2005, Duke Energy expects to continue to reduce debt principally through the payment of contractual debt maturities and to begin a stock repurchase program. The amount of debt reduction and repurchase of common stock is subject to certain factors including the use of existing cash, cash equivalents and short-term investments of $1.9 billion at December 31, 2004, the receipt of cash proceeds from the TEPPCO sale and DEFS restructuring and other market-driven investment opportunities.

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Duke Energy monitors compliance with all debt covenants and restrictions, and does not currently believe that it will be in violation or breach of its debt covenants. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings have stabilized. However, in February 2005, Moody’s Investor Service (Moody’s) changed the outlook for Duke Capital and DEFS to Negative, as a result of Duke Energy agreeing to transfer a 19.7% interest in DEFS to ConocoPhillips, Field Services’ selling TEPPCO, Duke Energy selling its limited partner interests in TEPPCO Partners, L.P. and the $2.5 billion stock repurchase announcement. In addition, Moody’s placed the credit ratings of Maritimes & Northeast Pipeline LLC and Maritimes & Northeast Pipeline LP under Review for Possible Downgrade in February 2005, due to concerns over downward revisions in gas reserve estimates for the Sable Offshore Energy Projects.

Operating Cash Flows

Net cash provided by operating activities was $4,139 million in 2004 compared to $3,396 million in 2003, an increase of $743 million. The increase in cash provided by operating activities was due primarily to higher cash settlements from trading and hedging activities, increased cash earnings related to Field Services, and increased cash flows in 2004 from changes in working capital related primarily to a cash refund received related to income taxes, which were partially offset by $86 million of increased pension plan contributions in 2004. Duke Energy made a voluntary contribution of $250 million to its U.S. defined benefit pension plan (U.S. plan) and a $28 million voluntary contribution to its Westcoast retirement plans (Westcoast plans in 2004). Duke Energy anticipates it will make no contributions to the U.S. plan and $33 million of contributions to the Westcoast plans in 2005.

Net cash provided by operating activities was $3,396 million in 2003 compared to $4,199 million in 2002, a decrease of $803 million. The decrease in cash provided by operating activities was due primarily to lower cash settlements from trading and hedging activities, and less cash flow in 2003 from changes in working capital, principally accounts payable and accounts receivable. Additionally, in 2003, Duke Energy made a voluntary contribution of $181 million to its U.S. plan; no contributions were made in 2002. Duke Energy also made contributions to the Westcoast plans of approximately $11 million in 2003 and $9 million in 2002.

In June 2002, the state of North Carolina passed new clean-air legislation that freezes electric utility rates from June 20, 2002, the effective date of the statute, to December 31, 2007 (rate-freeze period), subject to certain conditions, in order for certain North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state’s coal-fired power plants. The legislation permits Duke Energy the flexibility to vary the amortization schedule for expensing compliance costs. During the rate-freeze period, Duke Energy is expected to recover a minimum of 70% of the total estimated costs of compliance. As part of this legislation Duke Energy will spend an estimated total of $1.5 billion over the entire program, ending in 2011, to install pollution controls in its coal-fired plants. Cash outflows associated with this legislation were approximately $107 million in 2004. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters”.) Duke Energy anticipates cash outflows associated with this legislation to be approximately $285 million in 2005. As these cash outflows are funded by operating revenues from regulated electric customers, they are operating cash outflows, not capital and investment expenditures.

Investing Cash Flows

Cash used in investing activities was $764 million in 2004 compared to $668 million in 2003, an increase of $96 million. Cash used in investing activities was $668 million in 2003 compared to $6,954 million in 2002, a decrease of $6,286 million. The primary use of cash related to investing activities is capital and investment expenditures, detailed by business segment in the following table.

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Capital and Investment Expenditures by Business Segment (a)

	Years Ended December 31,
	2004		2003			2002
	(in millions)
Franchised Electric	$	1,020	$	997		$	1,269
Natural Gas Transmission		544		773			2,902
Field Services		202		204			285
DENA		22		277			2,013
International Energy		28		71			412
Crescent(b)		568		290			275
Other(c)		39		(21	)		136
Cash acquired in acquisitions		—		—			(77	)
Total consolidated	$	2,423	$	2,591		$	7,215

(a) Amounts include the acquisition of Westcoast in 2002

(b) Amounts include capital expenditures for residential real estate included in operating cash flows of $322 million in 2004, $196 million in 2003 and $179 million in 2002

(c) Amounts include deferral of the consolidation of 50% of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with Duke Energy’s share of ownership

Capital and investment expenditures, including Crescent’s residential real estate investments, decreased $168 million in 2004 compared to 2003. The decrease was due primarily to decreased investments in generating facilities at DENA due to the continuing downturn in the merchant energy portion of its business that began in 2002, and decreased investments at Gas Transmission due to the completion of infrastructure projects in western Canada and New England in 2003.

The increase in cash used in 2004 when compared to 2003 was also impacted by a $292 million increase in proceeds from the sales of commercial and multi-family real estate at Crescent, due primarily to sales of the Potomac Yard retail center and the Alexandria land tract in 2004.

These decreases in cash used were partially offset by a $424 million decrease in net proceeds received from the sales of equity investments and other assets, primarily related to sales in 2003 of DENA’s 50% ownership interest in Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline and its investments in the Alliance Pipeline and Vector Pipeline, LP (Vector); Field Services’ sale of certain gathering pipelines and gas processing plants; Duke Energy’s sale of its TEPPCO Class B units; DEM’s sale of DE Hydrocarbons, LLC and the monetization of various investments at DCP. These were partially offset by the sale of International Energy’s Asia-Pacific Business and DENA’s sale of its Southeast Plants and its Moapa and Luna partially completed facilities, and its Vermillion facilities, in 2004.

Capital and investment expenditures, including Crescent residential real estate investments, decreased $4,624 million in 2003 compared to 2002. The decrease was due primarily to the 2002 acquisition of Westcoast for $1,707 million, net of cash acquired, and lower investments in generating facilities at DENA, resulting from the downturn in the merchant energy portion of its business, the most significant of which were: a $621 million decrease due to 2002 expenditures on the Moapa, Grays Harbor, and Luna partially completed facilities; a $380 million decrease in expenditures for the Marshall, Sandersville, and Moss Landing facilities; and a $434 million decrease in turbine purchases. Capital and investment expenditures also decreased in 2003 due to lower plant construction costs at Franchised Electric, primarily due to an approximate $250 million decrease in expenditures related to environmental equipment at its coal-fired plants and the Mill Creek combustion turbine plant, which was completed in 2003; a $268 million decrease in plant construction costs at International Energy, primarily in Australia; a $226 million decrease in investments in Natural Gas Transmission’s 50% interest in Gulfstream; and a reduction in Other investments, primarily related to DCP.

The decrease in cash used in investing activities in 2003 when compared to 2002 was also impacted by an increase in proceeds from the sale of equity investments and other assets, and sales of and collections on notes receivable of $1,450 million. The increased proceeds were primarily due to the sale of DENA’s 50% ownership interest in Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline, sale of its investment in the Alliance Pipeline and the associated Aux Sable liquids plant, Foothills Pipe Lines, Ltd, and Vector; Field Services’ sale of certain gathering pipelines and gas processing plants, Duke Energy’s sale of its TEPPCO Partners, L.P. Class B units; DEM’s sale of DE Hydrocarbons LLC; International Energy’s sale of its 85.7% majority interest in P.T. Puncakjaya Power and its European Business; and the monetization of various investments at DCP.

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Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2004, including short-term debt, was 51% debt, 45% common equity and 4% minority interests. As a result of Duke Energy transferring a 19.7% interest in DEFS to ConocoPhillips, Field Services selling TEPPCO, Duke Energy selling its limited partner interest in TEPPCO Partners, L.P. and the announced $2.5 billion stock repurchase program, Duke Energy anticipates its debt to total capitalization ratio to be below 50% by the end of 2005. The fixed charges coverage ratio, calculated using Securities and Exchange Commission (SEC) guidelines, was 2.4 times for 2004 and 2.1 times for 2002. Earnings were inadequate to cover fixed charges by $19 million for the year ended December 31, 2003.

Net cash used in financing activities increased $621 million for the year ended December 31, 2004, compared to 2003. This change was due primarily to approximately $1.9 billion of higher net paydowns of long-term debt, commercial paper and notes payable in 2004 as compared to 2003, offset by approximately $1.4 billion of higher proceeds from common stock issuances during 2004, driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004. Total debt reductions of approximately $4.6 billion in 2004 consisted of $3.9 billion in cash redemptions (see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”) and approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of International Energy’s Asia-Pacific Business, which were partially offset by minimal issuances of long-term debt. The $840 million does not include the approximately $50 million of Asia-Pacific debt which was placed in trust and fully funded in connection with the closing of the sale transaction and repaid in September 2004. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business.

From 2002 to 2003 cash flows from financing activities decreased $5,503 million to net cash used in financing activities of $2,657 in 2003 from net cash provided by financing activities of $2,846 million in 2002. This change was due primarily to the net reduction of outstanding long-term debt, trust preferred securities, and notes payable and commercial paper during 2003 as compared to the same period in 2002 when Duke Energy acquired Westcoast and financed other business expansion projects. The change was also due to a reduction in the issuance of common stock in 2003 compared to 2002, when Duke Energy issued 54.5 million shares of common stock in a public offering, the proceeds of which were used to repay commercial paper that had been issued to fund a portion of the consideration for the Westcoast acquisition. This change in cash flows from financing activities was aligned with Duke Energy’s strategy to reduce outstanding debt and strengthen the balance sheet.

During 2004, cash from operations, the sale of non-strategic assets and the settlement of the forward stock purchase components of Duke Energy’s Equity Units in May and November 2004, were more than adequate for funding capital expenditures, dividend payments and planned debt reductions.

With cash, cash equivalents and short-term investments on hand at December 31, 2004 of $1.9 billion and a more stable business environment, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy is evaluating these options and will determine the best economic decision to meet the needs of shareholders and the long-term financial strength of Duke Energy. In connection with the TEPPCO and DEFS transactions discussed above, Duke Energy has announced plans to periodically repurchase up to an aggregate $2.5 billion of common stock over the next three years.

Significant Financing Activities. In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying its 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009 and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with EITF Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8.25% Equity Units in May 2004.

In March 2004, Duke Energy redeemed the entire issue of its 7.20% debt due to an affiliate in 2037 for approximately $350 million, in connection with the redemption of its Duke Energy Capital Trust I 7.20% Cumulative Quarterly Income Preferred Securities due in 2037. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued and unpaid distributions to the redemption date.

In April 2004, approximately $840 million of debt was retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific operations. In September 2004, Duke Energy repaid approximately $50 million of Asia-Pacific debt from assets that were held in a consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business. Duke Energy completed the sale of the Asia-Pacific assets, which includes substantially all of Duke Energy’s assets in Australia and New Zealand, to Alinta Ltd. on April 23, 2004.

In May 2004, Duke Energy issued 22,449,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in March 2001. Under the terms of the contract, the Equity Unit holders were

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required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement with a floor and a ceiling. The rate was 0.6414 shares of stock per Equity Unit. Duke Energy received $875 million in proceeds as a result of the settlement, which was included in issuances of common stock and common stock related to employee benefit plans on the Consolidated Statement of Cash Flows.

Also in May 2004, Duke Energy redeemed its Series C 6.60% senior notes due in 2038, at a $200 million face value. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued interest to the redemption date.

In June 2004, Duke Energy redeemed the entire issue of its 7.20% debt due to an affiliate in 2039 for approximately $250 million, in connection with the redemption of its Duke Energy Capital Trust II 7.20% Trust Preferred Securities. As the securities were redeemed at par, security holders received $25 per preferred security held, plus accrued and unpaid distributions to the redemption date.

In August 2004, Duke Energy redeemed the entire issue of its 8 ³/8% debt due to an affiliate in 2029 for $250 million, in connection with the redemption of its Duke Capital Financing Trust III 8 ³/8% Trust Preferred Securities. As the securities were redeemed at par, security holders received $25 per preferred security held, plus accrued and unpaid distributions to the redemption date.

Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8% Equity Units in November 2004.

In October 2004, Duke Energy prepaid a portion of a $994 million floating rate facility at DENA. The payment consisted of $565 million, an associated $35 million working capital facility and accrued interest on the facilities. Additionally, in December 2004, Duke Energy repaid the remaining outstanding balance of $429 million.

In November 2004, Duke Energy issued 18,693,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in November 2001. Under the terms of the contract, the Equity Unit holders were required to purchase stock at the time of settlement rate based on the current market price of Duke Energy’s common stock at the time of the settlement with a floor and a ceiling. The rate was 0.6231 shares of stock per Equity Unit. Duke Energy received $750 million in proceeds as a result of the settlement, which was included in issuances of common stock and common stock related to employee benefit plans on the Consolidated Statement of Cash Flows.

During 2004, Duke Capital purchased $202 million of its outstanding notes in the open market. These purchases included $140 million of Duke Capital 5.50% senior notes due March 1, 2014, $52 million of Duke Capital 4.37% senior notes due March 1, 2009, and $10 million of Duke Capital 6.75% senior notes due February 15, 2032. These securities were purchased at the then-current market price plus accrued interest.

Preferred and Preference Stock of Duke Energy’s Subsidiaries. In June 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.

In October 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 9. The Series 9 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of 125 million Canadian dollars.

Available Credit Facilities and Restrictive Debt Covenants. As of December 31, 2004, credit facilities capacity was reduced by approximately $560 million compared to December 31, 2003, primarily related to the divested Asia-Pacific Business as discussed in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.” In addition, Duke Energy and DEFS renewed and replaced their credit facilities at lower amounts due to the reduced need for credit capacity. In October 2004, Duke Capital added two new credit facilities, including a $120 million bilateral credit facility with an expiration date of July 15, 2009 and a $130 million bilateral credit facility with an expiration date of October 18, 2007. Duke Capital intends to use both of these facilities for issuing letters of credit to support the business activities of its subsidiaries. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2004, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

(For information on Duke Energy’s credit facilities as of December 31, 2004, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)

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Duke Energy has approximately $1,300 million of credit facilities which expire in 2005. It is Duke Energy’s intent to resyndicate the $1,300 million of expiring credit facilities.

Credit Ratings. The most recent change to the credit ratings of Duke Energy, Duke Capital and its subsidiaries occurred in February 2004, when Standard and Poor’s (S&P) lowered its long-term ratings of Duke Energy and its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) DEFS and DETM) one ratings level. S&P’s actions were based upon Duke Energy’s weaker than anticipated financial performance in 2003 and the execution risk associated with Duke Energy’s 2004 debt reduction plans. Additionally, S&P noted that Duke Energy’s continuation of trading and marketing activities around merchant generation will continue to expose Duke Energy to market risk and the need to dedicate material liquidity to support such activities. At the conclusion of S&P’s actions, Duke Energy, Duke Capital and its subsidiaries were placed on Stable Outlook, with the exception of DETM, which was changed from Negative Outlook to Stable in July 2004. In addition, S&P changed the outlook of all of Duke Energy and its subsidiaries (with the exception of M&N Pipeline and DEFS) from Stable to Positive in December 2004 and then from Positive to Stable in February 2005. Also, in February 2005, Moody’s changed the outlook of Duke Capital and DEFS from Stable to Negative and placed the ratings of M&N Pipeline to under Review for Possible Downgrade. The following table summarizes the March 1, 2005 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of March 1, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energya	BBB	Baa1	Not applicable
Duke Capital LLCa	BBB-	Baa3	Not applicable
Duke Energy Field Servicesa	BBB	Baa2	Not applicable
Texas Eastern Transmission, LPa	BBB	Baa2	Not applicable
Westcoast Energy Inc.a	BBB	Not applicable	A(low)
Union Gas Limiteda	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLCb	A	A1	A
Maritimes & Northeast Pipeline, LPb	A	A1	A
Duke Energy Trading and Marketing, LLCc	BBB-	Not applicable	Not applicable

a Represents senior unsecured credit rating

b Represents senior secured credit rating

c Represents corporate credit rating

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, and a disciplined execution of the stock repurchase program announced in February 2005, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.

Duke Energy and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Energy’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Energy’s collateral requirements. DENA transacts business through DETM or Duke Energy Marketing America, LLC, a wholly owned subsidiary of Duke Capital.

A reduction in DETM’s credit rating to below investment grade as of December 31, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $160 million. Additionally, in the event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of December 31, 2004, Duke Capital would have been required to escrow approximately $280 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Energy’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of December 31, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $380 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to termination of the agreements. As of December 31, 2004, Duke Capital could have been required to pay up to $140 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.

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

Acceleration Clauses. Duke Energy may be required to repay certain debt should its credit ratings fall to a certain level at S&P or Moody’s. As of December 31, 2004, Duke Energy had $17 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $28 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of March 1, 2004, Duke Energy’s senior unsecured credit rating was BBB at S&P and Baa1 at Moody’s.

Other Financing Matters. As of December 31, 2004, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,042 million in gross proceeds from debt and other securities. This represents an increase of approximately $92 million as compared to December 31, 2003, providing future funding flexibility. Of the total amount, $500 million represents available capacity at DEFS. On January 31, 2005 DEFS filed a Form 15 with the SEC to suspend its reporting obligations under the Securities and Exchange Act of 1934. Additionally, as of December 31, 2004, Duke Energy had access to 900 million Canadian dollars (U.S. $747 million) available under the Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 500 million Canadian dollars will expire in November 2005 and 400 million Canadian dollars will expire in July 2006.

Duke Energy’s Board of Directors adopted a dividend policy in 2000 that maintains dividends at the current quarterly rate of $0.275 per share, subject to the discretion of the Board of Directors. Duke Energy has paid quarterly cash dividends for 78 consecutive years. Dividends on common and preferred stocks in 2005 are expected to be paid on March 16, June 16, September 16 and December 16, subject to the discretion of the Board of Directors.

Prior to June 2004, Duke Energy’s Investor Direct Choice Plan allowed investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. In June 2004, Duke Energy changed the method of dividend reinvestment to open market purchases, reducing the issuances of common stock under the plan in 2004 to $36 million. Issuances under this plan were $111 million in 2003 and $105 million in 2002.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy, reducing the issuances of common stock under the plan to $51 million in 2004. Issuances of common stock under these plans were $156 million in 2003 and $188 million in 2002. Duke Energy also issues authorized but unissued shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $12 million for 2004, approximately $20 million for 2003 and approximately $50 million for 2002. (For additional information on stock-based compensation and employee benefit plans, see Note 20 to the Consolidated Financial Statements, “Stock-Based Compensation” and Note 21 to the Consolidated Financial Statements, “Employee Benefit Plan.”)

Off-Balance Sheet Arrangements

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. These arrangements are largely entered into by Duke Capital. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)

Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly-owned entities, enabling them to conduct business. As such, these guarantee arrangements 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 the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.

Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.

Duke Energy does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. (For additional information on these commitments, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)

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Contractual Obligations

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2005.

Contractual Obligations as of December 31, 2004

	Payments Due By Period
	Total		Less than 1 year (2005)		2-3 Years (2006 & 2007)		4-5 Years (2008 & 2009)		More than 5 Years (Beyond 2009)
	(in millions)
Long-term debt(a)	$	29,558	$	2,850	$	4,694	$	4,108	$	17,906
Capital leases(a)		195		119		28		30		18
Operating leases(b)		530		94		137		92		207
Purchase Obligations:
Firm capacity payments(c)		2,047		380		419		290		958
Energy commodity contracts(d)		11,746		4,948		4,321		1,412		1,065
Other purchase obligations(e)		1,973		800		369		136		668
Other long-term liabilities on the Consolidated Balance Sheets(f)		716		182		275		259		—
Total contractual cash obligations	$	46,765	$	9,373	$	10,243	$	6,327	$	20,822

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount also includes interest payments over life of debt.

(b) See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”.

(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to natural gas transportation and storage, electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some natural gas and power locations throughout North America. Also includes firm capacity payments under electric power agreements entered into to meet Franchised Electric’s native load requirements.

(d) Includes contractual obligations to purchase physical quantities of electricity, natural gas, NGLs, coal and nuclear fuel. Amount includes certain normal purchases, energy derivatives and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2004. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. A significant portion of these amounts pertain to DENA’s physical purchase commitments of electricity. Since DENA primarily markets electricity, consideration should be given to DENA’s forward sales of electricity, which exceed their forward purchases, when assessing the potential implications of these physical purchase commitments. (See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.)

(e) Includes purchase commitments for outsourcing of certain real estate services, contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for nuclear plant refurbishments, environmental projects on fossil facilities, pipeline and real estate projects, and major maintenance of certain merchant plants. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined.

(f) Includes expected retirement plan contributions for 2005 (see Note 21 to the Consolidated Financial Statements, “Employee Benefit Plan,”) certain estimated executive benefits, Department of Energy assessment fee (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters,”) and asset retirement obligations and contributions to the Nuclear Decommissioning Trust Funds (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) Duke Energy has not determined these amounts beyond 2009. Since the majority of asset retirement obligations will settle beyond 2009, they are excluded. Amount excludes reserves for litigation, environmental

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remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,”) funding of other post-employment benefits (see Note 21 to the Consolidated Financial Statements, “Employee Benefit Plan”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also amount excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Liabilities Associated with Assets Held for Sale (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Energy expects these liabilities will be assumed by the buyer upon sale of the assets.

Quantitative and Qualitative Disclosures About Market Risk

Risk and Accounting Policies

Duke Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Executive Committee which is composed of senior executives, receives periodic updates from the Chief Risk Officer (CRO) and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

See Critical Accounting Policies—Risk Management Accounting and Revenue Recognition—Trading and Marketing Revenues for further discussion of the accounting for derivative contracts.

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. 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. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

Validation of a contract’s fair value is performed by an internal group independent of Duke Energy’s trading areas. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Hedging Strategies. Duke Energy closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL forward contracts to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge the output and production of assets and other contractual positions it owns.

To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract unless the contract is designated as the hedged item in a fair value hedge. Normal purchases and sales contracts are generally subject to collateral requirements under the same credit risk reduction guidelines used for other contracts. Duke Energy has applied this scope exception for certain contracts involving the purchase and sale of electricity at fixed prices in future periods. As discussed in Critical Accounting Policies and Estimates for risk management activities, Duke Energy determined that substantially all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. Income statement recognition for the contracts will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness. The unrealized loss associated

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with DENA power forward sales contracts designated under the normal purchases and normal sales exemption as of December 31, 2004 and 2003 was approximately $900 million and $700 million, respectively. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power, and is partially offset by unrealized gains on natural gas positions of approximately $800 million and $400 million at December 31, 2004 and 2003, respectively, which are recorded on the Consolidated Balance Sheet in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. However, a key objective for Duke Energy in 2005 is to position DENA to be a successful merchant operator. Duke Energy is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. Depending on the option selected, there is a risk that material impairments or other losses could be recorded, including the potential disqualification of DENA’s power forward sales contracts designated under the normal purchases and normal sales exemption. This would result in the recognition of all unrealized losses associated with these forward contracts. (For more information, see discussion in Overview of Business Strategy in Introduction section of Management’s Discussion and Analysis). See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Energy’s decision to sell DENA’s Southeast Plants and reduce DENA’s interest in partially completed plants required the reassessment of all associated derivatives, including normal purchases and normal sales. This required a change from the application of the Accrual Model to the MTM Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Financial Statements. Future decisions about Duke Energy’s ownership of assets may result in additional contracts related to commodity price risk being recognized in the Consolidated Financial Statements through a charge or credit to earnings.

Based on a sensitivity analysis as of December 31, 2004, it was estimated that a difference of one cent and ten cents per gallon in the average price of NGLs in 2005 would have a corresponding effect on operating income of approximately $5 million and $48 million respectively (at Duke Energy’s 70% ownership), after considering the effect of Duke Energy’s commodity hedge positions. Comparatively, the same sensitivity analysis as of December 31, 2003 estimated that operating income would have changed by approximately $6 million and $62 million for a one cent and ten cents per gallon difference in the average price of NGLs in 2004, respectively. The effect on operating income for 2005 or 2004 was also not expected to be material as of December 31, 2004 or 2003 for exposures to other commodities’ price changes. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

As a result of the high probability of Duke Energy deconsolidating its investment in DEFS, during the first quarter of 2005 Duke Energy has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Energy related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result, approximately $140 million of pretax deferred losses in AOCI related to these contracts have been charged against earnings by Duke Energy in the first quarter of 2005. On a prospective basis, these contracts will be accounted for under the MTM Model and Duke Energy’s future earnings for 2005 and 2006 will be subject to more volatility.

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

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

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Daily Earnings at Risk (in millions)

	Period Ending One-Day Impact on Operating Income for 2004		Estimated Average One- Day Impact on Operating Income for 2004		Estimated Average One- Day Impact on Operating Income for 2003		High One- Day Impact on Operating Income for 2004(b)		Low One-Day Impact on Operating Income for 2004
Calculated DER(a)	$	6	$	16	$	8	$	49	$	5

(a) DER measures the MTM portfolio’s impact on earnings. While this calculation includes both trading and undesignated contracts, the trading portion, as defined by EITF Issue No. 02-03, is not material.

(b) This occurred on January 16, 2004.

DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk. The increase in estimated average DER for 2004 versus 2003 is primarily attributable to the DENA disqualified hedges included in the DER calculation for the full year in 2004 and only a portion of 2003 due to the timing of associated plant impairments and deferrals which resulted in the hedge disqualification.

During the first quarter of 2005, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity risk. Since these contracts will be accounted for under the MTM Model prospectively, Duke Energy’s 2005 DER figures are expected to be higher than the period ending 2004 DER and may, on average, be higher than the estimated average 2004 DER.

Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movement in the fair value of Duke Energy’s trading instruments during 2004.

Changes in Fair Value of Duke Energy’s Trading Contracts During 2004

	(in millions)
Fair value of contracts outstanding at the beginning of the year	$	177
Contracts realized or otherwise settled during the year		(116	)
Other changes in fair values		(7	)
Fair value of contracts outstanding at the end of the year	$	54

Fair Value of Duke Energy’s Trading Contracts as of December 31, 2004

Asset/(Liability) Sources of Fair Value	Maturity in 2005		Maturity in 2006		Maturity in 2007			Maturity in 2008 and Thereafter			Total Fair Value
	(in millions)
Prices supported by quoted market prices and other external sources	$	29	$	13	$	(12	)	$	(17	)	$	13
Prices based on models and other valuation methods		18		8		7			8			41
Total	$	47	$	21	$	(5	)	$	(9	)	$	54

The “prices supported by quoted market prices and other external sources” category includes Duke Energy’s New York Mercantile Exchange (NYMEX) futures positions in natural gas, crude oil, propane, heating oil, and unleaded gasoline. The NYMEX has quoted monthly natural gas prices for the next 72 months and quoted monthly crude oil prices for the next 30 months. The NYMEX has quoted monthly prices for varying periods of 18 months or less for propane, heating oil, and unleaded gasoline. In addition, this category includes Duke Energy’s forward positions and options in natural gas, natural gas basis swaps, and power at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for

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power and natural gas forwards and swaps extend 48 months into the future. OTC quotes for natural gas options extend 12 months into the future, on average. Duke Energy values these positions using internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by Duke Energy as simple forwards and options based on actively quoted prices. Although the valuation of the individual simple structures may be based on quoted market prices, the effective model price for any given period is a combination of prices from two or more different instruments and such transactions therefore are included in this category due to its complex nature. As a result of the adoption of EITF Issue No. 02-03 in January 2003, all of the contracts in the “prices based on models and other valuation methods” category as of December 31, 2004 are derivatives as defined by SFAS No. 133.

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 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.

The following table represents Duke Energy’s distribution of unsecured credit exposure with the largest 30 enterprise credit exposures at December 31, 2004. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.

Distribution of Largest 30 Enterprise Credit Exposures

As of December 31, 2004

	% of Total
Investment Grade—Externally Rated	69	%
Non-Investment Grade—Externally Rated	10	%
Investment Grade—Internally Rated	16	%
Non-Investment Grade—Internally Rated	5	%
Total	100	%

“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Energy utilizes appropriate risk rating methodologies and credit scoring models to develop an internal risk rating which is intended to map to an external rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 33% of the gross fair value of Duke Energy’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheet at December 31, 2004.

Duke Energy had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2004. Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its financial position or results of operations as a result of non-performance by any counterparty.

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its marketing and trading operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

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Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Energy or its affiliates have a credit rating downgrade, it could result in reductions in Duke Energy’s unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy and its affiliates. (See Liquidity and Capital Resources—Financing Cash Flows and Liquidity for additional discussion of downgrades.)

The change in market value of NYMEX-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.

Interest Rate Risk

Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. (See Notes 1, 8, 15, and 16 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” “Debt and Credit Facilities,” and “Preferred and Preference Stock at Duke Energy.”)

Based on a sensitivity analysis as of December 31, 2004, it was estimated that if market interest rates average 1% higher (lower) in 2005 than in 2004, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $8 million. Comparatively, based on a sensitivity analysis as of December 31, 2003, had interest rates averaged 1% higher (lower) in 2004 than in 2003, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $34 million. These amounts were estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term investments, cash and cash equivalents outstanding as of December 31, 2004 and 2003. The decrease in interest rate sensitivity was primarily due to a decrease in subsidiary debt and a decrease in outstanding variable-rate commercial paper, net of invested cash. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy’s financial structure.

Equity Price Risk

Duke Energy maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning. (See Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) As of December 31, 2004 and 2003, these funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents. Per NRC and Internal Revenue Service mandates, these funds may be used only for activities related to nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear decommissioning recognizes that costs are recovered through Franchised Electric’s rates, fluctuations in equity prices or interest rates do not affect consolidated results of operations or cash flows.

Bison, Duke Energy’s wholly-owned captive insurance subsidiary, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.

Duke Energy’s costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by changes in the equity market since 2000. As a result, at September 30, 2004 (Duke Energy’s measurement date), Duke Energy’s pension plan obligation, excluding Westcoast, exceeded the value of the plan assets by $130 million and Duke Energy was therefore required to reduce the minimum pension liability as prescribed by SFAS No. 87 and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits,” by approximately $39 million to $650 million. The $650 million minimum pension liability was a combination of the $130 million excess obligation and $520 million in pre-paid pension assets as of the measurement date of September 30, 2004. The net pension assets as of December 31, 2004 of $120 million, which reflects a fourth quarter 2004 contribution of $250 million is included in Other Investments and Other

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Assets on the Consolidated Balance Sheets. The minimum liability was recorded as a reduction to AOCI, net of income taxes, and did not affect net income for 2004. When the fair value of the plan assets exceeds the accumulated benefit obligations on the measurement date, the recorded liability will be reduced and AOCI will be restored in the Consolidated Balance Sheets. Also, Westcoast has a $22 million minimum pension liability recorded as of December 31, 2004.

Foreign Currency Risk

Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. Dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

As of December 31, 2004, Duke Energy’s primary foreign currency rate exposures were the Canadian Dollar and the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of approximately $25 million to Duke Energy’s Consolidated Statements of Operations. The Consolidated Balance Sheets would be negatively impacted by approximately $450 million currency translation through the cumulative translation adjustment in AOCI.

OTHER ISSUES

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

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

Due to the uncertainty of the Canadian policy and the speculative nature of any U.S. federal and state policies, Duke Energy cannot estimate the potential effect of the Canadian greenhouse gas reduction policy currently under development, or the potential effect of U.S. greenhouse gas policy on future consolidated results of operations, cash flows or financial position. Duke Energy will continue to assess and respond to the potential implications of greenhouse gas policies applicable to its business operations in the United States and Canada.

(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of December 31, 2004:

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

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The impact on earnings per share (EPS) for 2004, 2003 and 2002 had Duke Energy followed the expensing provisions of SFAS No. 123 is discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.” Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. The impact to Duke Energy in periods subsequent to adopting SFAS 123R will be dependent upon the nature of any equity-based compensation awards issued to employees, but Duke Energy does not anticipate the adoption of SFAS No. 123R on July 1, 2005 to have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December of 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 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact to Duke Energy of SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Energy does not currently expect SFAS No. 153 to have a material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, ‘Accounting for the Impairment or Disposal of Long-Lived Assets’, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The impact to Duke Energy of EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Energy does not currently expect EITF Issue No. 03-13 to have a material impact on its consolidated results of operations, cash flows or financial position.

Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-K for the year ended December 31, 2004, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

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

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. During 2005, Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $.8 billion in cash and approximately $.3 billion of assets. The DEFS disposition resulted in pre-tax gain of approximately $575 million in third quarter 2005. The DEFS

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disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. In connection with the DEFS disposition, Duke Energy acquired ConocoPhillips interest in the Empress System gas processing and natural gas liquids marketing business (Empress System) in August 2005 for cash of approximately $230 million.

Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see also Note 3 to the Consolidated Financial Statements).

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

Acquisitions and Dispositions - DENA. As described in Note 13 to the Consolidated Financial Statements, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

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

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

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

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

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

47

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

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

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

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

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

Pro forma Cinergy Merger Transaction Value

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

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

Regulatory Matters - Franchised Electric. On March 9, 2005, Duke Power Company (Duke Power) filed with the North Carolina Utilities Commission a proposed fuel rate increase, for rates effective July 1, 2005 for a twelve-month period. To reduce the impact of the increased cost of fuel, Duke Power is seeking approval in the fuel case proceeding to credit the deferred fuel account by approximately $100 million for previously recorded excess deferred tax liabilities that are recorded as regulatory liabilities. The filing has not yet been approved. No similar action has yet been proposed to the PSCSC.

Debt and Credit Facilities. On March 1, 2005, notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. The bondholders were notified that these securities would be called on April 15, 2005, the earliest date at which these bonds can be redeemed.

Common Stock. In connection with the Field Services transactions discussed above, Duke Energy announced plans to periodically repurchase up to an aggregate of $2.5 billion of common stock over the next three years.

Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”

Part II, Item 8. Financial Statements and Supplementary Data.

Management’s Annual Report on Internal Control Over Financial Reporting

Duke Energy’s management is responsible for establishing and maintaining an adequate system of internal controls over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Duke Energy’s management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2004 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2004.

48

Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which immediately follows.

March 16, 2005

49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Duke Energy Corporation:

We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, that Duke Energy Corporation and subsidiaries (Duke Energy) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Duke Energy’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of Duke Energy’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Duke Energy maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Duke Energy maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of Duke Energy and our report dated March 16, 2005 (December 9, 2005 as to the references to the Duke Energy North America discontinued operations and the segment changes in the “Reclassifications and Other Changes” section of Note 1, and the reference to “Acquisitions and Dispositions-Cinergy Merger” in Note 23) expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding Duke Energy’s agreement in February 2005 to sell its interests in TEPPCO to Enterprise GP Holdings L.P. and to transfer a 19.7% interest in Duke Energy Field Services to ConocoPhillips.

DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 16, 2005

50

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Duke Energy Corporation:

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (Duke Energy) as of December 31, 2004 and 2003, and the related consolidated statements of operations, common stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of Duke Energy’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1, Duke Energy adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” as of January 1, 2002. As discussed in Note 1 and Note 7, Duke Energy adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. As discussed in Note 1, Duke Energy adopted the provisions of Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” as of July 1, 2003. As discussed in Note 1, Note 15, and Note 16, Duke Energy adopted the provisions of Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” as of July 1, 2003. As discussed in Note 1, Duke Energy adopted the provisions of Emerging Issues Task Force No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003.

As discussed in Note 23, Duke Energy agreed in February 2005 to sell its interests in TEPPCO to Enterprise GP Holdings L.P. and to transfer a 19.7% interest in Duke Energy Field Services to ConocoPhillips.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Duke Energy’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of Duke Energy’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Duke Energy’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 16, 2005

(December 9, 2005 as to the references to the Duke Energy North America discontinued operations and the segment changes in the “Reclassifications and Other Changes” section of Note 1, and the reference to “Acquisitions and Dispositions-Cinergy Merger” in Note 23)

51

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per-share amounts)

	Years Ended December 31,
	2004			2003			2002
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids, and other	$	12,232		$	10,088		$	7,700
Regulated electric		5,041			4,851			4,799
Regulated natural gas		3,276			3,082			2,253
Total operating revenues		20,549			18,021			14,752
Operating Expenses
Natural gas and petroleum products purchased		10,156			8,479			5,383
Operation, maintenance and other		3,317			3,496			3,179
Fuel used in electric generation and purchased power		1,576			1,465			1,612
Depreciation and amortization		1,750			1,675			1,397
Property and other taxes		513			499			509
Impairments and other related charges		64			1,219			313
Impairment of goodwill		—			254			—
Total operating expenses		17,376			17,087			12,393
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		192			84			106
(Losses) Gains on Sales of Other Assets, net		(404	)		(199	)		32
Operating Income		2,961			819			2,497
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		161			123			232
(Losses) Gains on sales and impairments of equity investments		(4	)		279			32
Other income and expenses, net		148			148			105
Total other income and expenses		305			550			369
Interest Expense		1,281			1,330			1,116
Minority Interest Expense		200			62			91
Earnings (Loss) From Continuing Operations Before Income Taxes		1,785			(23	)		1,659
Income Tax Expense (Benefit) from Continuing Operations		533			(94	)		514
Income From Continuing Operations		1,252			71			1,145
Discontinued Operations
Net operating (loss) income, net of tax		(147	)		(1,101	)		(111	)
Net gain (loss) on dispositions, net of tax		385			(131	)		—
Income (Loss) From Discontinued Operations		238			(1,232	)		(111	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		1,490			(1,161	)		1,034
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			(162	)		—
Net Income (Loss)		1,490			(1,323	)		1,034
Dividends and Premiums on Redemption of Preferred and Preference Stock		9			15			13
Earnings (Loss) Available For Common Stockholders	$	1,481		$	(1,338	)	$	1,021
Common Stock Data
Weighted-average shares outstanding		931			903			836
Earnings per share (from continuing operations)
Basic	$	1.33		$	0.06		$	1.35
Diluted	$	1.29		$	0.06		$	1.35
Earnings (Loss) per share (from discontinued operations)
Basic	$	0.26		$	(1.36	)	$	(0.13	)
Diluted	$	0.25		$	(1.36	)	$	(0.13	)
Earnings (Loss) per share (before cumulative effect of change in accounting principle)
Basic	$	1.59		$	(1.30	)	$	1.22
Diluted	$	1.54		$	(1.30	)	$	1.22
Earnings (Loss) per share
Basic	$	1.59		$	(1.48	)	$	1.22
Diluted	$	1.54		$	(1.48	)	$	1.22
Dividends per share	$	1.10		$	1.10		$	1.10

See Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002

52

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2004		2003
ASSETS
Current Assets
Cash and cash equivalents	$	533	$	397
Short-term investments		1,319		763
Receivables (net of allowance for doubtful accounts of $135 at 2004 and $280 at 2003)		3,237		2,953
Inventory		942		941
Assets held for sale		40		361
Unrealized gains on mark-to-market and hedging transactions		962		1,566
Other		938		694
Total current assets		7,971		7,675
Investments and Other Assets
Investments in unconsolidated affiliates		1,292		1,398
Nuclear decommissioning trust funds		1,374		925
Goodwill		4,148		3,962
Notes receivable		232		260
Unrealized gains on mark-to-market and hedging transactions		1,379		1,857
Assets held for sale		84		1,444
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $15 and $32 at December 31, 2004 and 2003, respectively)		1,128		1,353
Other		1,896		2,137
Total investments and other assets		11,533		13,336
Property, Plant and Equipment
Cost		46,806		45,987
Less accumulated depreciation and amortization		13,300		12,139
Net property, plant and equipment		33,506		33,848
Regulatory Assets and Deferred Debits
Deferred debt expense		297		275
Regulatory assets related to income taxes		1,269		1,152
Other		894		939
Total regulatory assets and deferred debits		2,460		2,366
Total Assets	$	55,470	$	57,225

See Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002

53

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2004		2003
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	2,414	$	2,317
Notes payable and commercial paper		68		130
Taxes accrued		273		14
Interest accrued		287		304
Liabilities associated with assets held for sale		30		651
Current maturities of long-term debt		1,832		1,200
Unrealized losses on mark-to-market and hedging transactions		819		1,283
Other		1,815		1,849
Total current liabilities		7,538		7,748
Long-term Debt, including debt to affiliates of $876 at 2003		16,932		20,622
Deferred Credits and Other Liabilities
Deferred income taxes		5,228		4,120
Investment tax credit		154		165
Unrealized losses on mark-to-market and hedging transactions		971		1,754
Liabilities associated with assets held for sale		14		737
Asset retirement obligations		1,926		1,707
Other		4,646		4,789
Total deferred credits and other liabilities		12,939		13,272
Commitments and Contingencies
Minority Interests		1,486		1,701
Preferred and Preference Stock without Sinking Fund Requirements		134		134
Common Stockholders’ Equity
Common stock, no par, 2 billion shares authorized; 957 million and 911 million shares outstanding at December 31, 2004 and 2003, respectively		11,252		9,519
Retained earnings		4,539		4,060
Accumulated other comprehensive income		650		169
Total common stockholders’ equity		16,441		13,748
Total Liabilities and Common Stockholders’ Equity	$	55,470	$	57,225

See Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002

54

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,490		$	(1,323	)	$	1,034
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		2,037			1,987			1,692
Cumulative effect of change in accounting principle		—			162			—
Gains on sales of investments in commercial and multi-family real estate		(201	)		(103	)		(106	)
Gains on sales of equity investments and other assets		(193	)		(86	)		(81	)
Impairment charges		194			3,495			545
Deferred income taxes		867			(534	)		495
Purchased capacity levelization		92			194			175
Contribution to company-sponsored pension plan		(278	)		(192	)		(9	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		216			(15	)		596
Receivables		(188	)		1,126			12
Inventory		(48	)		(30	)		134
Other current assets		(35	)		(77	)		(335	)
Increase (decrease) in
Accounts payable		(5	)		(1,047	)		798
Taxes accrued		188			(168	)		(332	)
Other current liabilities		116			79			(194	)
Capital expenditures for residential real estate		(322	)		(196	)		(179	)
Cost of residential real estate sold		268			167			117
Other, assets		(305	)		(249	)		205
Other, liabilities		246			206			(368	)
Net cash provided by operating activities		4,139			3,396			4,199
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures, net refund		(2,055	)		(2,242	)		(4,745	)
Investment expenditures		(46	)		(153	)		(584	)
Acquisition of Westcoast Energy Inc., net of cash acquired		—			—			(1,707	)
Purchases of available-for-sale securities		(64,594	)		(40,032	)		(12,393	)
Proceeds from sales and maturites of available-for-sale securities		64,092			39,641			11,859
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,542			1,966			516
Proceeds from the sales of commercial and multi-family real estate		606			314			169
Other		(309	)		(162	)		(69	)
Net cash used in investing activities		(764	)		(668	)		(6,954	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		153			3,009			5,114
Issuance of common stock and common stock related to employee benefit plans		1,704			277			1,323
Payments for the redemption of:
Long-term debt		(3,646	)		(2,849	)		(1,837	)
Preferred stock of a subsidiary		(176	)		(38	)		—
Preferred and preference stock		—			—			(88	)
Guaranteed preferred beneficial interests in subordinated notes		—			(250	)		—
Notes payable and commercial paper		(67	)		(1,702	)		(1,067	)
Distributions to minority interests		(1,477	)		(2,508	)		(2,260	)
Contributions from minority interests		1,277			2,432			2,535
Dividends paid		(1,065	)		(1,051	)		(938	)
Other		19			23			64
Net cash (used in) provided by financing activities		(3,278	)		(2,657	)		2,846
Changes in cash and cash equivalents associated with assets held for sale		39			(55	)		—
Net increase in cash and cash equivalents		136			16			91
Cash and cash equivalents at beginning of year		397			381			290
Cash and cash equivalents at end of year	$	533		$	397		$	381
Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	1,323		$	1,324		$	1,011
Cash (refunded) paid for income taxes	$	(339	)	$	(18	)	$	344
Significant non-cash transactions:
Debt retired in connection with disposition of businesses	$	840		$	387		$	—
Note receivable from sale of southeast plants	$	48		$	—		$	—
Remarketing of senior notes	$	1,625		$	—		$	—
Acquisition of Westcoast Energy Inc.
Fair value of assets acquired	$	—		$	—		$	9,254
Liabilities assumed, including debt and minority interests		—			—			8,047
Issuance of common stock		—			—			1,702
Capital lease obligations related to property, plant and equipment	$	—		$	—		$	117

See Notes to Consolidated Financial Statements

55

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

(In millions)

							Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares	Common Stock		Retained Earnings			Foreign Currency Adjustments			Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Total
Balance December 31, 2001	777	$	6,217	$	6,292		$	(307	)	$	487		$	—		$	12,689
Net income	—		—		1,034			—			—			—			1,034
Other Comprehensive Income
Foreign currency translation adjustments	—		—		—			(340	)		—			—			(340	)
Net unrealized gains on cash flow hedges (b)	—		—		—			—			37			—			37
Reclassification into earnings from cash flow hedges (c)	—		—		—			—			(102	)		—			(102	)
Minimum pension liability adjustment (d)	—		—		—			—			—			(484	)		(484	)
Total comprehensive income																	145
Dividend reinvestment and employee benefits	13		342		—			—			—			—			342
Equity offering	55		975		—			—			—			—			975
Westcoast Acquisition	50		1,702		—			—			—			—			1,702
Common stock dividends	—		—		(905	)		—			—			—			(905	)
Preferred and preference stock dividends	—		—		(13	)		—			—			—			(13	)
Other capital stock transactions, net	—		—		9			—			—			—			9
Balance December 31, 2002	895	$	9,236	$	6,417		$	(647	)	$	422		$	(484	)	$	14,944
Net loss	—		—		(1,323	)		—			—			—			(1,323	)
Other Comprehensive Loss
Foreign currency translation adjustments (a)	—		—		—			986			—			—			986
Foreign currency translation adjustments reclassified into earnings as a result of the sale of European operations	—		—		—			(24	)		—			—			(24	)
Net unrealized gains on cash flow hedges (b)	—		—		—			—			116			—			116
Reclassification into earnings from cash flow hedges (c)	—		—		—			—			(240	)		—			(240	)
Minimum pension liability adjustment (d)	—		—		—			—			—			40			40
Total comprehensive loss																	(445	)
Dividend reinvestment and employee benefits	16		283		(6	)		—			—			—			277
Common stock dividends	—		—		(993	)		—			—			—			(993	)
Preferred and preference stock dividends	—		—		(15	)		—			—			—			(15	)
Other capital stock transactions, net	—		—		(20	)		—			—			—			(20	)
Balance December 31, 2003	911	$	9,519	$	4,060		$	315		$	298		$	(444	)	$	13,748
Net income	—		—		1,490			—			—			—			1,490
Other Comprehensive Income
Foreign currency translation adjustments	—		—		—			279			—			—			279
Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business	—		—		—			(54	)		—			—			(54	)
Net unrealized gains on cash flow hedges (b)	—		—		—			—			311			—			311
Reclassification into earnings from cash flow hedges (c)	—		—		—			—			(83	)		—			(83	)
Minimum pension liability adjustment (d)	—		—		—			—			—			28			28
Total comprehensive income																	1,971
Dividend reinvestment and employee benefits	5		108		20			—			—			—			128
Equity offering	41		1,625		—			—			—			—			1,625
Common stock dividends	—		—		(1,018	)		—			—			—			(1,018	)
Preferred and preference stock dividends	—		—		(9	)		—			—			—			(9	)
Other capital stock transactions, net	—		—		(4	)		—			—			—			(4	)
Balance December 31, 2004	957	$	11,252	$	4,539		$	540		$	526		$	(416	)	$	16,441

(a) Foreign currency translation adjustments, net of $114 tax benefit in 2003.

(b) Net unrealized gains on cash flow hedges, net of $170 tax expense in 2004, $49 tax expense in 2003, and $72 tax expense in 2002.

(c) Reclassification into earnings from cash flow hedges, net of $45 tax benefit in 2004, $130 tax benefit in 2003, and $94 tax benefit in 2002.

(d) Minimum pension liability adjustment, net of $18 tax expense in 2004, $27 tax expense in 2003, and $309 tax benefit in 2002.

See Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

For the Years Ended December 31, 2004, 2003 and 2002

1. Summary of Significant Accounting Policies

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. The Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy, all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. The Consolidated Financial Statements also reflect Duke Energy’s 12.5% undivided interest in Catawba Nuclear Station.

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 financial statements and notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Reclassifications and Other Changes. Certain prior period amounts have been reclassified to conform to current year presentation. Such reclassifications include the reclassification of income from continuing operations to discontinued operations for certain operations (see Note 13). Except as required to reflect the effects of the Duke Energy North America (DENA) discontinued operations classification discussed in Note 13, the segment changes discussed in Note 3 and the Cinergy merger discussed in Note 23, the financial statements have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-K for the year ended December 31, 2004. These changes impacted Note 2 (Consolidated Pro Forma Results for Duke Energy, including Westcoast, Proceeds from Sales of Assets and Businesses, and also gains or losses on sales), Note 3, Note 6, Note 8 (Commodity Cash Flow Hedges and Commodity Fair Value Hedges), Note 10, Note 11, Note 12, Note 13, Note 19, Note 22, and Note 23.

The accompanying Consolidated Balance Sheet as of December 31, 2003 reflects a reclassification of instruments used in Duke Energy’s cash management program from cash and cash equivalents to short-term investments of $763 million. This reclassification is to present certain auction rate securities and other highly-liquid instruments as short-term investments rather than as cash equivalents due to the stated tenor of the maturities of these investments. Corresponding changes were made to the Consolidated Statements of Cash Flows for the years ended December 31, 2003 and 2002, resulting in reductions of $763 million and $493 million, respectively, in amounts presented as Cash and Cash Equivalents. In the Consolidated Statements of Cash Flows, Cash and Cash equivalents of $493 million at December 31, 2002 was also revised to reflect the reclassification of these instruments from Cash and Cash Equivalents to Short-Term Investments (See Note 9 for further information).

The accompanying Consolidated Balance Sheet as of December 31, 2003 reflects an adjustment of Other within noncurrent assets of $1,020 million, Other Deferred Credits and Other Liabilities of $970 million and Other Current Liabilities of $50 million for a gross-up of insurance receivables and related accrued reserves. This adjustment is related to Duke Energy’s contingent exposure related to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos as discussed further in Note 17 and the resulting probable reinsurance recoveries related to Duke Energy’s insurance policy covering such losses.

Cash and Cash Equivalents. All highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.

Short-term Investments. Duke Energy actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Energy intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are classified as current assets. Duke Energy has classified all short-term investments that are debt securities as available-for-sale under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as they do not have readily determinable fair values. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings at the time they are earned.

Inventory. Inventory consists primarily of materials and supplies; natural gas and natural gas liquid (NGL) products held in storage for transmission, processing and sales commitments; and coal held for electric generation. This inventory is recorded at the lower of cost or market value, primarily using the average cost method.

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Components of Inventory

	December 31,
	2004		2003
	(in millions)
Materials and supplies	$	445	$	445
Natural gas		312		299
Coal		104		87
Petroleum products		81		110
Total inventory	$	942	$	941

Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Energy uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities and its trading activities, including forward contracts, futures, swaps, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions.

Effective January 1, 2003, in connection with the implementation of the remaining provisions of Emerging Issues Task Force (EITF) Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” Duke Energy designated all energy commodity derivatives as either trading or non-trading. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of the Duke Energy’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.

Classification of Contract	Duke Energy Accounting Model	Presentation of Gains & Losses or Revenue & Expense
Trading derivatives Non-trading derivatives:	Mark-to-market(a)	Net basis in Non-regulated Electric, Natural Gas, NGL, and Other
Cash flow hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Fair value hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Normal purchase or sale	Accrual(b)	Gross basis upon settlement in the corresponding income statement category based on commodity type
Undesignated	Mark-to-market(a)	Net basis in the related income statement category for interest rate, currency and commodity derivative.

(a) An accounting term used by Duke Energy to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within U. S. Generally Accepted Accounting Principles, Duke Energy’s application of this term could differ from that of other companies

(b) An accounting term used by Duke Energy to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further below, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within U. S. Generally Accepted Accounting Principles, Duke Energy’s application of this term could differ from that of other companies.

Prior to January 1, 2003, unrealized and realized gains and losses on all energy trading contracts, as defined in EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which included many derivative and non-derivative instruments, were presented on a net basis in Trading and Marketing Net Margin within Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other in the Consolidated Statements of Operations. While the income statement presentation of gains and losses, or revenues and expenses for each category of non-trading derivatives, as

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described above, remained consistent from 2002 to 2003, the definition of a trading and non-trading instrument changed from EITF Issue No. 98-10 to EITF Issue No. 02-03. Under EITF Issue No. 98-10, all energy derivative and non-derivative contracts were considered to be trading that were entered into by an entity’s energy trading operations, while under EITF Issue No. 02-03 an assessment is performed for each contract, and only those individual derivative contracts that are entered into with the intent of generating profits on short-term differences in price are considered to be trading. As a result, a significant number of derivatives previously classified as trading under EITF Issue No. 98-10 became classified as non-trading as of January 1, 2003. The significant reduction, as of January 1, 2003, in the volume of derivative and non-derivative contracts that were considered to be trading resulted in presentation of gains and losses, or revenues and expenses for many contracts on a gross basis in 2003 that were presented on a net basis in 2002.

Where Duke Energy’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation No. 39 (FIN 39), “Offsetting of Amounts Related to Certain Contracts—An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105,” are met, Duke Energy presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets.

Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Duke Energy provides formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and on a quarterly basis Duke Energy formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Energy documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk/interest rate risk).

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged item. Duke Energy discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the Mark-to-Market Model of Accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is no longer probable that the hedged forecasted transaction will occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

For derivatives designated as fair value hedges, Duke Energy recognizes the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings, to the extent effective, in the current period. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.

Normal Purchase and Normal Sales. From July 1, 2001 through June 30, 2003, Duke Energy applied the normal purchase and normal sale scope exception in Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” to certain forward sale contracts to deliver electricity. In connection with the adoption of SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” on July 1, 2003, Duke Energy has elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 continue to be accounted for under the normal purchase and normal sales exception as long as the requirements for applying the exception are met. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the MTM Model unless immediately designated as a cash flow or fair value hedge.

Valuation. When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models. For derivatives recognized under the MTM Model, valuation adjustments are also recognized in the Consolidated Statements of Operations.

Goodwill. Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” Under this provision, goodwill is subject to an annual test for impairment. Duke Energy has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, Duke Energy performs the annual review for goodwill impairment at the reporting unit level, which Duke Energy has determined to be an operating segment or one level below.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.

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Duke Energy uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporates current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices.

During the quarter ended September 30, 2004, the date of the annual goodwill impairment test for Field Services was changed to August 31st from September 30th. August 31st was selected to perform the annual goodwill impairment test because this earlier date allows Field Services to complete the goodwill impairment test within the same quarter as the testing date. In addition, the change in date will be consistent with the annual goodwill impairment test date used by Duke Energy’s other business segments. The change in testing goodwill date did not delay, accelerate or avoid an impairment charge. Accordingly, management believes that the accounting change described above is to a date which is preferable under the circumstances.

Other Long-term Investments. Other long-term investments, primarily marketable securities held in the Nuclear Decommissioning Trust Funds (NDTF) and the captive insurance investment portfolio, are classified as available-for-sale securities as management does not have the intent and ability to hold the securities to maturity, nor are they bought and held principally for selling them in the near term. The securities are reported at fair value on Duke Energy’s Consolidated Balance Sheets. Unrealized and realized gains and losses, net of tax, on the NDTF are reflected in regulatory assets on Duke Energy’s Consolidated Balance Sheets as Duke Energy expects to recover all costs for decommissioning its nuclear generation assets through regulated rates. Unrealized holding gains and losses, net of tax, on all other available-for-sale securities are reflected in AOCI in Duke Energy’s Consolidated Balance Sheets until they are realized and reflected in net income.

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates, excluding nuclear fuel, were 3.81% for 2004, 4.15% for 2003 and 4.32% for 2002. Also, see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below.

When Duke Energy retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income, unless otherwise required by the applicable regulatory body.

Duke Energy recognizes asset retirement obligations (ARO) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations,” for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the estimated useful life of the asset.

Investments in Residential, Commercial, and Multi-Family Real Estate. Investments in residential, commercial and multifamily real estate are carried at cost, net of any related depreciation, except for any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,” to be presented as Assets Held for Sale in the Consolidated Balance Sheets. Proceeds from sales of residential properties are presented within Operating Revenues and the cost of properties sold are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multifamily properties as well as “legacy” land sales are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Duke Energy evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.

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Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset, or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.

Duke Energy uses the criteria in SFAS No. 144 to determine when an asset is classified as “held for sale.” Upon classification as “held for sale,” the long-lived asset or asset group is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset or asset group is separately presented on the Consolidated Balance Sheets.

If an asset or asset group held for sale or sold has clearly distinguishable operations and cash flows, and Duke Energy will not have significant continuing involvement in the operations after the disposal and cash flows of the assets sold have been eliminated from Duke Energy’s ongoing operations, then the related results of operations for the current and prior periods, including any related impairments, are reflected as Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not qualify for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Related Charges in the Consolidated Statements of Operations.

Captive Insurance Reserves. Duke Energy has captive insurance subsidiaries which provide insurance coverage to Duke Energy entities as well as certain third parties, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred, but not yet reported (IBNR), as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience. Intercompany balances and transactions are eliminated in consolidation.

Duke Energy’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Energy for certain losses above a per incident retention. Duke Energy’s captive insurance entities also have an aggregate stop-loss insurance coverage, which provides reimbursement from third parties to Duke Energy for its paid losses above certain per line of coverage aggregate amounts during a policy year. Duke Energy recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance and stop-loss insurance coverage once realization of the receivable is deemed probable.

During 2004, Duke Energy eliminated intercompany reserves at its captive insurance subsidiaries of approximately $64 million which was a correction of an accounting error related to prior periods.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate. Certain debt costs were expensed on an accelerated basis in 2003 as required by the Public Service Commission of South Carolina (PSCSC) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” (See Cost-Based Regulation below for further discussion of SFAS No. 71.)

Environmental Expenditures. Duke Energy expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated.

Cost-Based Regulation. Duke Energy accounts for certain of its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company recording costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. Duke Energy periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. (For further information see Note 4).

Guarantees. Duke Energy accounts for guarantees and related contracts, for which it is the guarantor, under FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect

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Guarantees of Indebtedness of Others.” In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Energy recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee. Fair value is estimated using a probability-weighted approach. Duke Energy reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts is accounted for and recognized in accordance with SFAS No. 5, “Accounting for Contingencies.”

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

Stock-Based Compensation. Duke Energy accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and the FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are recorded over the vesting period as compensation cost, and are adjusted for increases and decreases in market value up to the measurement date. Compensation expense for awards with pro-rata vesting is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”

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, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards and reflects the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment to SFAS No. 123).”

Pro Forma Stock-Based Compensation

	For the years ended December 31,
	2004			2003			2002
	(in millions, except per share amounts)
Earnings (loss) available for common stockholders, as reported	$	1,481		$	(1,338	)	$	1,021
Add: stock-based compensation expense included in reported net income (loss), net of related tax effects		16			6			9
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(27	)		(30	)		(70	)
Pro forma earnings (loss) available for common stockholders, net of related tax effects	$	1,470		$	(1,362	)	$	960
Earnings (loss) per share
Basic—as reported	$	1.59		$	(1.48	)	$	1.22
Basic—pro forma	$	1.58		$	(1.51	)	$	1.15
Diluted—as reported	$	1.54		$	(1.48	)	$	1.22
Diluted—pro forma	$	1.53		$	(1.51	)	$	1.15

Revenue Recognition. Revenues on sales of electricity, primarily at Franchised Electric, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered, but not billed. Differences between actuals and estimates are immaterial.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered, but not yet billed, are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.

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Crescent LLC (Crescent) sells residential developed lots in North Carolina, South Carolina, Georgia, Florida, Texas and Arizona. Crescent recognizes revenues from the sale of residential developed lots at closing. Profit is recognized under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs are allocated to land sold based on relative sales values. Crescent recognizes revenues from commercial and multifamily project sales at closing using the full accrual method. Profit is recognized based on the difference between the sales price and the carrying cost of the project. Crescent develops and sells condominium units in Florida, and revenue is recognized under the percentage-of-completion method.

Nuclear Fuel. Amortization of nuclear fuel purchases is included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. The amortization is recorded using the units-of-production method.

Deferred Returns and AFUDC. Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding regulatory assets. Those costs arise primarily from the funding of purchased capacity costs above levels collected in rates. Deferred returns are non-cash items and are primarily recognized as an addition to purchased capacity costs, which are included in Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets, with an offsetting credit to Other Income and Expenses, net. The amount of deferred returns included in Other Income and Expenses, net was ($9) million in 2004, $6 million in 2003 and $24 million in 2002.

AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment Cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Energy is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $39 million in 2004, which consisted of an equity component of $25 million and an interest expense component of $14 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $108 million in 2003, which consisted of an equity component of $74 million and an interest expense component of $34 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $82 million in 2002, which consisted of an equity component of $55 million and an interest expense component of $27 million.

Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

Management evaluates and records contingent tax liabilities and related interest based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.

Excise and Other Pass-Through Taxes. Duke Energy presents revenues net of pass-through taxes on the Consolidated Statements of Operations.

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single operating segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the company’s general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, are presented in Note 3.

Foreign Currency Translation. The local currencies of Duke Energy’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Transaction gains and losses, which were not material for all periods presented, are included in the results of operations of the period in which they occur. Deferred taxes are not provided on translation gains and losses where Duke Energy expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.

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Cumulative Effect of Changes in Accounting Principles. As of January 1, 2003, Duke Energy adopted the remaining provisions of EITF Issue No. 02-03 and SFAS No. 143. In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings.

In October 2002, the EITF reached a final consensus on EITF Issue No. 02-03. Primarily, the final consensus provided for (1) the rescission of the consensus reached on EITF Issue No. 98-10, (2) the reporting of gains and losses on all derivative instruments considered to be held for trading purposes to be shown on a net basis in the income statement, and (3) gains and losses on non-derivative energy trading contracts to be similarly presented on a gross or net basis, in connection with the guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

As a result of the consensus on EITF Issue No. 02-03, Duke Energy recorded a cumulative effect adjustment of $151 million (net of tax and minority interest) in the first quarter 2003 as a reduction to earnings. The recorded value on January 1, 2003 of all non-derivative energy trading contracts that existed on October 25, 2002 were written-off and inventories that were recorded at fair values were adjusted to historical cost. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods and, therefore, Duke Energy did not change the 2002 classification of operating revenue and operating expense amounts.

In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. For obligations related to non-regulated operations, a cumulative effect adjustment of $11 million (net of tax and minority interest) was recorded in the first quarter of 2003, as a reduction in earnings.

New Accounting Standards. The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51,” which supercedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FASB Staff Positions related to the application of FIN 46.

The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Energy), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy).

Duke Energy has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003, which require consolidation or disclosure under FIN 46R. Under the provisions of FIN 46R, effective March 31, 2004, Duke Energy has consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These entities, which are substantive entities, had total assets of approximately $230 million as of December 31, 2004. In addition, as of December 31, 2004 and 2003, Duke Energy has recorded Net Property, Plant and Equipment of $112 million and $112 million, respectively, and Long-term Debt of $168 million and $157 million, respectively, on the Consolidated Balance Sheets, associated with a variable interest entity that is consolidated by Duke Energy. Duke Energy leases a natural gas processing plant from this entity, and retains all rights and obligations associated with the operations of this plant. This variable interest entity was consolidated on Duke Energy’s Consolidated Financial Statements prior to March 31, 2004 (the effective date of FIN46R) primarily due to Duke Energy’s guarantee of the residual value of the assets. The impact of consolidating these entities on Duke Energy’s consolidated financial statements was not material. Duke Energy adopted the provisions of FIN 46R on December 31, 2003, related to its special-purpose entities consisting of its remaining trust subsidiaries that issued trust preferred securities. Since Duke Energy is not the primary beneficiary of those trust subsidiaries, those entities have been deconsolidated in the accompanying Consolidated Financial Statements. Interest paid to the subsidiary trust is classified as Interest Expense in the accompanying Consolidated Statements of Operations for periods after December 31, 2003. The preferred securities issued by these trusts were repaid during 2004. Additionally, Duke Energy previously had a significant variable interest in, but was not the primary beneficiary of Duke COGEMA Stone & Webster LLC (DCS). However, due to certain contract clarifications pursuant to a contract amendment entered into in April 2004, Duke Energy no longer holds a significant variable interest in DCS.

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Various changes and clarifications to the provisions of FIN 46 have been made by the FASB since its original issuance in January 2003. While not anticipated at this time, any additional clarifying guidance or further changes to these complex rules could have an impact on Duke Energy’s Consolidated Financial Statements.

SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” In December 2003, the FASB revised the provisions of SFAS No. 132 to include additional disclosures related to defined-benefit pension plans and other defined-benefit post-retirement plans, such as the following:

• The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used

• Information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc.) along with the targeted allocation percentage of plan assets for each category and the actual allocation percentages at the measurement date

• The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate

• The current best estimate of the range of contributions expected to be made in the following year

• The accumulated benefit obligation for defined-benefit pension plans

• Disclosure of the measurement date utilized.

Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of SFAS No. 132R do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of SFAS No. 132R were applied by Duke Energy effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Energy for the year ended December 31, 2004. (See Note 21 for the additional related disclosures).

FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In May 2004, the FASB staff issued FSP FAS 106-2, which superseded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.

The provisions of FSP FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. (See Note 21 for discussion of the effects of adopting this FSP).

FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”. On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in FASB Statement No. 109. As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the periods in which the deductions are claimed on the tax returns.

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

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decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Energy plans to repatriate approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly has recorded a corresponding tax liability of $45 million as of December 31, 2004. However, Duke Energy has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences in our non-U.S. subsidiaries that result primarily from undistributed earnings of $150 million, which Duke Energy intends to reinvest indefinitely. Determination of the deferred tax liability on these basis differences is not practicable because such liability, if any, is dependent on circumstances existing if and when remittance occurs.

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

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

EITF Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share.” In September 2004, the EITF reached a consensus on Issue No. 04-8. The consensus requires that the potential common stock related to contingently convertible securities (Co-Cos) with market price contingencies be included in diluted earnings per share calculations using the if-converted method specified in SFAS No. 128, “Earnings per Share,” whether the market price contingencies have been met or not. Co-Cos generally require conversion into a company’s common stock if certain specified events occur, such as a specified market price for the company’s common stock. Prior to the issuance of EITF Issue No. 04-08, Co-Cos were treated as contingently issuable shares under SFAS No. 128, and therefore, the contingencies, must have been met in order for the potential common shares to be included in diluted EPS. Therefore, Co-Cos were only included in diluted EPS during periods in which the contingencies had been met. The consensus is effective for fiscal years ended after December 15, 2004 and is required to be applied retroactively to all periods in which any Co-Cos were outstanding, resulting in restatement of diluted EPS if the impact of the Co-Cos was dilutive.

As discussed in Note 15, Duke Energy issued $770 million par value of contingently convertible notes in May of 2003, bearing an interest rate of 1.75% per annum that contain several contingencies, including a market price contingency that, if met, may require conversion of the notes into Duke Energy common stock. Conversion may be required, at the option of the holder, if any one of the contingencies is met. Therefore, as discussed in Note 19, Duke Energy has included potential common shares of 32.6 million in the calculation of diluted EPS for the periods in which the $770 million contingently convertible notes have been outstanding and for which the impact of conversion was dilutive.

The following accounting standards were adopted by Duke Energy during the year ended December 31, 2003 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” In April 2003, the FASB issued SFAS No. 149, which amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities, including the qualifications for the normal purchases and normal sales exception, under SFAS No. 133. This amendment reflects decisions made by the FASB and the DIG process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 were to be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after September 30, 2003. The provisions of SFAS No. 149 which resulted from the DIG process and became effective in quarters beginning before June 15, 2003 continue to be applied based on their original effective dates. Duke Energy adopted the provisions of SFAS No. 149 on July 1, 2003. Certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity led Duke Energy to re-evaluate its accounting policy for forward sales contracts. As a result, Duke Energy elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges on a prospective basis. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 will continue to be accounted for under such exception, including any modifications to those contracts, as long as the requirements for applying the normal purchases and normal sales exception are met.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” In May 2003, the FASB issued SFAS No. 150 which establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equities. Under SFAS No. 150, those instruments are required to be classified as liabilities in the statement of financial position. The financial instruments affected include mandatorily redeemable stock, certain financial instruments that require or may require the issuer to buy back some of its shares in

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exchange for cash or other assets, and certain obligations that can be settled with shares of stock. SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and has been applied to Duke Energy’s existing financial instruments beginning July 1, 2003.

Duke Energy’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited-life entities, which are required to be liquidated or dissolved on a certain date, based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests under FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” Duke Energy has a controlling interest in a limited-life entity in Bolivia, which is required to be liquidated 99 years after formation. A non-controlling interest in the entity is held by third parties. Upon termination or liquidation of the entity in 2094, the remaining assets of the entity are to be sold, the liabilities liquidated and any remaining cash distributed to the owners based upon their ownership percentages. As of December 31, 2004 the carrying value of the entity’s non-controlling interest of approximately $48 million approximates its fair value. Duke Energy continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant future changes could be made by the FASB. Therefore, Duke Energy is not able to conclude whether such future changes would materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.

EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” In May 2003, the EITF reached consensus in EITF Issue No. 01-08 to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” Duke Energy has historically provided and leased storage capacity to outside parties, as well as entered into pipeline and electricity capacity agreements, both as the lessee and as a lessor. The accounting requirements under the consensus may impact the timing of revenue and expense recognition, and amounts previously reported as revenues may be required to be reported as rental or lease income. Should capital lease treatment be necessary, purchasers of transportation, electricity capacity and storage services are required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired on or after July 1, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for under historical accounting. The adoption of EITF Issue No. 01-08 did not have a material effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In July 2003, the EITF reached consensus in EITF Issue No. 03-11 that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on relevant facts and circumstances and the economic substance of the transaction. In analyzing those facts and circumstances, EITF Issue No. 99-19, “Reporting Revenue Gross as a Principle versus Net as an Agent,” and APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF Issue No. 03-11 was effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF Issue No. 03-11 did not have a material effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of December 31, 2004:

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

The impact on EPS for 2004, 2003 and 2002 had Duke Energy followed the expensing provisions of SFAS No. 123 is discussed above in the Pro Forma Stock-Based Compensation table. Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. The impact to Duke Energy in periods subsequent to adopting SFAS No. 123R will be dependent upon the nature of any equity-based compensation awards issued to employees, but Duke Energy does not anticipate the adoption of SFAS No. 123R on July 1, 2005 to have any material impact on its consolidated results of operations, cash flows or financial position.

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

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The impact to Duke Energy of EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Energy does not currently expect EITF Issue No. 03-13 to have a material impact on its consolidated results of operations, cash flows or financial position.

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

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

In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which Duke Energy Field Services LLC (DEFS) owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Energy recognizing a pretax impairment of approximately $13 million, which was approximately $4 million net of minority interest, which is discussed in Note 12. An additional 12% interest in Dauphin Island Gathering Partners (DIGP) was also purchased for $2 million, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

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

On March 14, 2002, Duke Energy acquired Westcoast Energy Inc. (Westcoast) for approximately $8 billion, including the assumption of $4.7 billion of debt. In the transaction, a Duke Energy subsidiary acquired all of the outstanding common

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shares of Westcoast in exchange for approximately $1.7 billion in cash (net of cash acquired) and approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock). The value of the Duke Energy common stock issued was approximately $1.7 billion and was determined based on the average market price of Duke Energy’s common shares over the two-day period before and after the terms of the transaction became fixed, in accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination.” Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, or either 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities (Equity Units) in November 2001, along with incremental commercial paper. The commercial paper was repaid using the proceeds from the October 2002 public offering of Duke Energy Common Stock.

The acquisition of Westcoast was consistent with Duke Energy’s natural gas pipeline strategy to expand its footprint between key supply and market areas in North America. During its evaluation, Duke Energy identified revenue enhancement opportunities through expansion projects and business integration, cost reduction initiatives, and the divestiture of several non-strategic business lines and assets. These initiatives, when combined with the ongoing earnings contributions from Westcoast’s pipelines and distribution businesses, supported a purchase price in excess of the fair value of Westcoast’s assets, which resulted in the recognition of goodwill. The Westcoast acquisition was accounted for using the purchase method, and goodwill to the Natural Gas Transmission segment of approximately $2.3 billion was recorded in the transaction, of which approximately $57 million was expected to be deductible for income tax purposes. Of the $57 million, $52 million was allocated for tax purposes to Empire State Pipeline which was sold in February 2003.

During 2003, Duke Energy recorded additional purchase price adjustments as information regarding the assets acquired became available, including adjustments related to the sale of Empire State Pipeline and adjustments recorded to reflect the revised tax basis of certain acquired assets, with an offsetting increase to goodwill attributable to the acquisition.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date, including the adjustments described above.

Purchase Price Allocation for Westcoast Acquisition

	(in millions)
Current assets	$	2,050
Investments and other assets		1,207
Goodwill		2,269
Property, plant and equipment		4,991
Regulatory assets and deferred debits		809
Total assets acquired		11,326
Current liabilities		1,655
Long-term debt		4,132
Deferred credits and other liabilities		1,678
Minority interests		560
Total liabilities assumed		8,025
Net assets acquired	$	3,301

The following unaudited pro forma consolidated financial results are presented as if the acquisition had taken place at the beginning of the period presented.

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Consolidated Pro Forma Results for Duke Energy, including Westcoast (unaudited)

	For the year ended December 31, 2002
	(in millions, except per share amounts)
Income Statement Data
Operating revenues	$	15,070
Net income		1,071
Preferred and preference stock dividends		13
Earnings available to common stockholders	$	1,058
Common Stock Data
Weighted-average shares outstanding		846
Earnings per share
Basic	$	1.25
Diluted	$	1.25

Dispositions. The following table details proceeds from the sale of Duke Energy’s assets and businesses for 2004, 2003 and 2002.

Proceeds from Sales of Assets and Businesses

	For the years ended December 31,
	2004			2003			2002
	(in millions)
Sales of discontinued operations (see Note 13)(a)	$	1,590		$	693		$	45
Sales which were recorded as purchase price adjustments to the Westcoast acquisition (see above disclosure)(b)		—			243			53
Sales of other assets and businesses(c)		832			1,190			214
Cash disposed of in sales		—			(16	)		—
Net proceeds, including debt assumed by buyers and note receivable from buyer		2,422			2,110			312
Non-cash debt assumed by buyers and note received from sale of assets		(888	)		(387	)		—
Proceeds included in the Consolidated Statements of Cash Flows(d)	$	1,534		$	1,723		$	312

(a) 2004 includes approximately $840 million of debt assumed by buyer; 2003 includes $259 million of debt assumed by buyer

(b) 2003 includes $58 million of debt assumed by buyer

(c) 2004 includes $48 million note receivable from buyer; 2003 includes $70 million of debt assumed by buyer

(d) Excludes investing activities related to sales and collections of notes receivable of $8 million for 2004, $243 million for 2003 and $204 million for 2002, and proceeds from sales of Crescent’s commercial and multi-family real estate of $606 million for 2004, $314 million for 2003, and $169 million for 2002

For the year ended December 31, 2004, the sale of other assets and businesses (which excludes assets held for sale as of December 31, 2004 and discontinued operations, both of which are discussed in Note 13, and sales by Crescent which are discussed separately below) resulted in approximately $784 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $404 million recorded in (Losses) Gains on Sales of Other Assets, net and pre-tax losses of $4 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. (Losses) Gains on Sales and Impairments of Equity Investments includes a $23 million impairment charge, which is discussed in Note 13. Significant sales of other assets in 2004 are detailed as follows:

• Natural Gas Transmission’s asset sales totaled $25 million in net proceeds. Those sales resulted in total pre-tax gains of approximately $33 million, of which $17 million was recorded in (Losses) Gains on Sales of Other Assets, net and $16 million was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included the sale of storage gas related to the Canadian distribution operations, the sale of Natural Gas Transmission’s interest in the Millennium Pipeline, and the sale of land.

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• Field Services asset sales totaled $13 million in net proceeds. Those sales resulted in gains of $2 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. These sales consisted of multiple small sales.

• DENA’s asset sales totaled approximately $572 million in net proceeds and a $48 million note receivable. Those sales resulted in pre-tax losses of $427 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included:

• DENA’s eight natural gas-fired merchant power plants in the southeastern United States: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi); and certain other power and gas contracts (collectively, the Southeast Plants). Duke Energy decided to sell the Southeast Plants in 2003, and recorded an impairment charge of $1.3 billion in 2003 since the assets’ carrying values exceeded their estimated fair values (see Note 12). The sale of those assets to KGen Partners LLC (KGen) obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a pre-tax loss of approximately $360 million recorded in (Losses) Gains on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. Nearly all of the loss was recognized in the first quarter of 2004 to reduce the assets’ carrying values to their estimated fair values, and approximately $4 million of the loss was recognized in the third quarter of 2004 upon closing. The fair value of the plants used for recording the loss in the first quarter was based on the sales price of approximately $475 million, as announced on May 4, 2004. The actual sales price consisted of $420 million of cash and a $48 million note receivable from KGen, which bears variable interest at the London Interbank Offered Rate (LIBOR) plus 13.625% per annum, compounded quarterly. The note is secured by a fourth lien on (i) substantially all of KGen’s assets and (ii) stock of KGen LLC (KGen’s owner), each subject to certain permitted liens and a first lien on cash in certain KGen accounts. The note matures with a balloon payment of all principal and interest due no later than 7 years and 6 months after the closing date.

Duke Capital LLC (Duke Capital) retains certain guarantees related to the sold assets. In conjunction with the sale, Duke Capital arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from one of the plants to Georgia Power. Duke Capital is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Capital for any payments made by it under the letter of credit, as well as expenses incurred by Duke Capital in connection with the letter of credit. DENA will continue to provide services under a long-term operating agreement for one of the plants. As a result of DENA’s significant continuing involvement in the operations of the plants, this transaction did not qualify for discontinued operations presentation, as prescribed by SFAS No. 144. However, this continuing involvement does not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.”

• Some turbines and surplus equipment. This sale was anticipated in 2003 and therefore a loss of $66 million was recorded in (Losses) Gains on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations.

• Some Duke Energy Trading and Marketing, LLC (DETM) contracts. DETM held a net liability position in those contracts and, as part of the sale, DETM paid a third party an amount approximating the carrying value of the contracts. The net cash payments of $99 million related to the sale of these assets are included in Cash Flows from Operating Activities. This resulted in a net loss of $65 million recorded in (Losses) Gains on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations.

• A 25% undivided interest in DENA’s Vermillion facility. This sale was anticipated in 2003 and therefore losses of $18 million were recorded in (Losses) Gains on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations. Duke Energy still owns the remaining 75% interest in the Vermillion facility.

• International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico on September 8, 2004. The sale resulted in $60 million in net proceeds and an approximate $2 million pre-tax gain recorded to (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. A $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations, related to a note receivable from Cantarell, was recorded in the first quarter of 2004.

• Additional asset and business sales in 2004 totaled $114 million in net proceeds. Those sales resulted in net pre-tax gains of $5 million, of which $4 million was recorded in (Losses) Gains on Sales of Other Assets, net and $1 million was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included Duke Energy Royal LLC’s interest in six energy service agreements, DukeSolutions Huntington Beach LLC, and Duke Energy Merchant LLC’s (DEM’s) 15% ownership interest in Caribbean Nitrogen Company. DEM also sold its refined products operation in the eastern United States.

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For the year ended December 31, 2004, Crescent’s commercial and multi-family real estate sales resulted in $606 million of proceeds, and $192 million of net gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Significant sales included commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March; real estate sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area; and several large land tract sales.

The sale of other assets and businesses for approximately $1,120 million in proceeds plus the assumption of $70 million of debt by the buyers for 2003 resulted in net losses of $199 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations, and gains of $279 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales of other assets and businesses in 2003 (other than discontinued operations as presented in Note 13, and sales which were recorded as purchase price adjustments to the Westcoast acquisition as presented above) are detailed by business segment as follows:

• Natural Gas Transmission’s sales of assets and businesses totaled $610 million in proceeds, and the assumption of $70 million of debt by the buyers. Those sales resulted in gains of $90 million which were recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations, and gains of $7 million which were recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included the sale of its remaining limited partnership interests in Northern Border Partners L.P.; the sale of its investments in the Alliance Pipeline and the associated Aux Sable NGL plant, Foothills Pipe Lines Ltd., and Vector Pipeline LP (Vector); the sale of Pacific Northern Gas Ltd., and the sale of two office buildings.

• Field Services sales of assets totaled $141 million in proceeds. Those sales resulted in gains of $11 million which were recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included Field Services’ Class B units of TEPPCO Partners, L.P.

• DENA’s asset sales totaled $372 million in proceeds. The sale of DENA’s 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) resulted in a gain of $178 million, which was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations.

• Impairment charges and net losses on sales, primarily related to the sale of DETM contracts, resulted in a net loss of $124 million, which was recorded in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Impairment charges and losses on the DETM contracts resulted from DENA’s decision to wind-down DETM’s operations. As a result, DENA and ExxonMobil, its partner, are executing a reduction of DETM business in scope and scale and soliciting interest from selected parties for a significant portion of DETM’s contract portfolio. The ultimate financial impact to DENA of the reduction in the scope and sale of DETM and related liquidation of its contract portfolio cannot be reasonably estimated. However, it is possible that DENA will incur additional losses as a result of liquidating the DETM contracts.

The sale of other assets and businesses for approximately $214 million in gross proceeds for 2002 resulted in gains of $32 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statement of Operations, and gains of $32 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statement of Operations. Significant sales of other assets and businesses in 2002 are detailed by business segment as follows:

• Natural Gas Transmission’s sales of assets totaled $81 million in proceeds. Those sales resulted in gains of $32 million, which were included in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included a portion of Natural Gas Transmission’s limited partnership interests in Northern Border Partners L.P.

• Sales of assets and businesses previously included in Other totaled $133 million in proceeds. Those sales resulted in gains of $32 million, which were included in (Losses) Gains on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included portions of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) businesses, and the sale of Duke Energy’s remaining water operations.

3. Business Segments

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

Franchised Electric generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. It conducts operations through Duke Power. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the PSCSC.

Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail

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customers in Ontario, and natural gas processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC. Duke Energy Gas Transmission, LLC’s natural gas transmission and storage operations in the U.S. are primarily subject to the FERC’s and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Texas Eastern Transmission LP (Texas Eastern) is an indirect subsidiary of Natural Gas Transmission and was also a separate Securities and Exchange Commission (SEC) reporting entity. On December 15, 2004 Texas Eastern announced that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. Texas Eastern is eligible to suspend its reporting obligation under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLS. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Energy. Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. DEFS, which previously was a separate SEC reporting entity, announced January 31, 2005 that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. DEFS is eligible to suspend its reporting obligations under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, closed in July 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company LLC (TEPPCO), the general partner of TEPPCO Partners L.P., for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to Enterprise GP Holdings L.P. (EPCO), an unrelated third party. TEPPCO Partners L.P. is a publicly traded master limited partnership which owns one of the largest common-carrier pipelines of refined petroleum products and liquefied petroleum gases in the United States, as well as natural gas gathering systems, petrochemical and natural gas liquid pipelines, and is engaged in crude oil transportation, storage, gathering and marketing. TEPPCO is responsible for the management and operations of TEPPCO Partners, L.P.

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% (the DEFS disposition transaction). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Energy’s Natural Gas Transmission segment. All segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while all segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy. 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. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. All segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE).

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Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the southeastern and southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.

The remainder of Duke Energy’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet), Duke Energy Merchants, LLC (DEM), 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). DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations. During 2003, Duke Energy determined that it would exit the refined products business at DEM in an orderly manner, and continues to unwind its portfolio of contracts. As of December 31, 2004, DEM had exited the majority of its business. Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. Bison also participates in reinsurance activities with certain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. During 2003, Duke Energy decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). DCP had been previously included in Other. At December 31, 2004, Duke Energy had exited the merchant finance business, and all of the results of operations for DCP have been classified as discontinued operations in the accompanying Consolidated Statements of Operations.

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 Note 1. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).

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

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

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Business Segment Data^(a)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT/ Consolidated Earnings (Loss) from Continuing Operations before Income Taxes			Depreciation and Amortization		Capital and Investment Expenditures			Segment Assets(b)
	(in millions)
Year Ended December 31, 2004
Franchised Electric	$	5,045		$	24		$	5,069		$	1,467		$	863	$	1,020		$	18,199
Natural Gas Transmission		3,239			112			3,351			1,329			431		544			17,498
Field Services		10,172			(128	)		10,044			368			285		202			6,436
DENA		103			70			173			(585	)		72		22			6,719
International Energy		619			—			619			222			58		28			3,329
Crescent(c)		437			—			437			240			2		568			1,315
Total reportable segments		19,615			78			19,693			3,041			1,711		2,384			53,496
Other		934			210			1,144			(77	)		39		39			1,829
Eliminations		—			(288	)		(288	)		—			—		—			145
Interest expense		—			—			—			(1,281	)		—		—			—
Minority interest expense and other(d)		—			—			—			102			—		—			—
Total consolidated	$	20,549		$	—		$	20,549		$	1,785		$	1,750	$	2,423		$	55,470
Year Ended December 31, 2003
Franchised Electric	$	4,854		$	21		$	4,875		$	1,403		$	748	$	997		$	17,240
Natural Gas Transmission		3,025			228			3,253			1,333			404		773			16,727
Field Services		7,921			617			8,538			176			281		204			6,095
DENA		(25	)		192			167			(1,676	)		135		277			9,165
International Energy		597			—			597			215			57		71			4,550
Crescent(c)		284			—			284			134			6		290			1,653
Total reportable segments		16,656			1,058			17,714			1,585			1,631		2,612			55,430
Other		1,365			263			1,628			(272	)		44		(21	)		2,585
Eliminations		—			(1,321	)		(1,321	)		—			—		—			(790	)
Interest expense		—			—			—			(1,330	)		—		—			—
Minority interest expense and other(d)		—			—			—			(6	)		—		—			—
Total consolidated	$	18,021		$	—		$	18,021		$	(23	)	$	1,675	$	2,591		$	57,225
Year Ended December 31, 2002
Franchised Electric	$	4,880		$	8		$	4,888		$	1,595		$	614	$	1,269		$	14,642
Natural Gas Transmission		2,279			227			2,506			1,170			333		2,902			15,463
Field Services		4,795			1,115			5,910			139			272		285			6,536
DENA		1,525			(1,149	)		376			(75	)		81		2,013			13,470
International Energy		737			6			743			102			54		412			5,803
Crescent(c)		226			—			226			158			8		275			1,685
Total reportable segments		14,442			207			14,649			3,089			1,362		7,156			57,599
Other		188			115			303			(368	)		35		136			3,357
Eliminations,and reclassifications		122			(322	)		(200	)		—			—		—			(834	)
Interest expense		—			—			—			(1,116	)		—		—			—
Minority interest expense and other(d)											54			—
Cash acquired in acquisitions		—			—			—			—			—		(77	)		—
Total consolidated	$	14,752		$	—		$	14,752		$	1,659		$	1,397	$	7,215		$	60,122

(a) Segment results exclude results of entities classified as discontinued operations

(b) Includes assets held for sale

(c) Capital expenditures for residential properties are included in operating cash flows on the Consolidated Statement of Cash Flows. Capital expenditures for commercial and multi-family properties are included in investing cash flows on the Consolidated Statement of Cash Flows.

(d) Includes interest income, foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

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Geographic Data

	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(in millions)
2004
Consolidated revenues	$	16,584	$	3,297	$	612	$	56	$	20,549
Consolidated long-lived assets		34,938		9,863		2,399		299		47,499
2003
Consolidated revenues	$	12,403	$	4,935	$	556	$	127	$	18,021
Consolidated long-lived assets		36,240		9,272		2,449		1,589		49,550
2002
Consolidated revenues	$	12,818	$	1,194	$	674	$	66	$	14,752
Consolidated long-lived assets		38,138		7,895		2,118		2,234		50,385

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4. Regulatory Matters

Regulatory Assets and Liabilities. Duke Energy’s regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (For further information see Note 1.)

Duke Energy’s Regulatory Assets and Liabilities (a):

	As of December 31,				Recovery/Refund Period Ends
	2004		2003
	(in millions)
Regulatory Assets
Net regulatory asset related to income taxes(b)	$	1,269	$	1,152	(l	)
Asset retirement obligation (ARO) costs(c)		519		547	2043
Deferred debt expense(d)		181		169	2039
Vacation accrual(c)		73		70	2005
U.S. Department of Energy (DOE) assessment fee(c)		23		33	2007
Demand-side management costs(d)(e)		—		18	(m	)
Project costs(c)(d)		16		17	2024
Hedge costs and other deferrals(c)		10		2	2005
Under-recovery of fuel costs(i)		9		—	2006
Environmental cleanup costs(c)		8		8	2017
Total Regulatory Assets	$	2,108	$	2,016
Regulatory Liabilities
Removal costs(d)(g)(h)	$	982	$	1,207	(n	)
North Carolina clean air compliance(d)(g)		199		95	2011
Other deferred tax credits(d)(g)		164		160	(o	)
Nuclear property and liability reserves(d)(g)		162		157	2043
Purchased capacity costs (For further information see Note 5.)(d)(j)		135		43	(p	)
Pipeline rate credit(g)		38		40	2041
Over-recovery of fuel costs(f)		—		30	2005
South Carolina rate decrement(k)		—		23	2004
Gas purchase costs(f)		32		14	2005
Storage and transportation liability(f)		16		9	2005
Earnings sharing liability(f)		11		10	2005
Demand-side management costs(d)(e)		5		—	(m	)
Total Regulatory Liabilities	$	1,744	$	1,788

(a) All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) Natural Gas Transmission’s amounts are expected to be included in future rate filing, $893 million at December 31, 2004 and $772 million at December 31, 2003. Franchised Electric’s amounts are included in rate base, $376 million at December 31, 2004 and $380 million at December 31, 2003.

(c) Included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets

(d) Included in rate base, earns a return

(e) In 2004 included in Other Regulatory Assets and Deferred Debits and Other Deferred Credits and Other Liabilities and in 2003 included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets

(f) Included in Accounts Payable on the Consolidated Balance Sheets

(g) Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets

(h) In 2004 Duke Energy contributed $262 million in cash to the nuclear decommissioning trust fund for its non-legally obligated nuclear decommissioning costs related to plant components not subject to radioactive contamination. In 2003 these costs were internally reserved as removal costs and classified as a regulatory liability. (For further information see Note 7.)

(i) Included in Receivables on the Consolidated Balance Sheets

(j) In 2004 included in Other Current Liabilities and Other Deferred Credits and Other Liabilities and in 2003 included in Other Current Assets, Other Regulatory Assets and Deferred Debits, Other Current Liabilities, and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets

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(k) Included in Other Current Liabilities on the Consolidated Balance Sheets

(l) Recovery/refund is over the life of the associated asset or liability

(m) Incurred costs were deferred and are being recovered in rates. Franchised Electric is currently over-recovered for these costs. Refund period is dependent on volume of sales and cost incurrence.

(n) Refund is over the lives of the associated assets

(o) Duke Power is seeking approval from the NCUC to credit approximately $100 million for previously recorded excess deferred tax liabilities against fuel rates effective July 1, 2005. (For further information see Note 23.)

(p) Incurred costs were deferred and are being recovered in rates. Franchised Electric is currently over-recovered for these costs and is refunding the liability through retail rates. Refund period will be determined by the volume of sales.

Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power.

FERC Audits of Pre-Order 2004 Standards of Conduct. In July 2003, the FERC initiated a public audit of compliance with the pre-Order 2004 standards of conduct by Duke Power as an electric transmission provider and its wholesale merchant function and affiliates. Additionally, in September 2003, the FERC initiated a public audit of compliance with the pre-Order 2004 standards of conduct by Texas Eastern.

The Duke Power audit was closed by the FERC on January 21, 2005. The FERC approved and directed several actions that Duke Power had proposed and implemented to address FERC concerns about full compliance. No penalties were proposed or recommended by the FERC.

On February 28, 2005, the FERC approved a settlement agreement with regard to the Texas Eastern audit. The agreement includes a settlement payment of $500 thousand by Texas Eastern and a compliance plan under which Texas Eastern and its marketing affiliates will adopt certain new procedures.

The FERC’s findings have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Franchised Electric. Rate Related Information. The NCUC and the PSCSC approve rates for retail electric sales within their states. The FERC approves Franchised Electric’s rates for electric sales to regulated wholesale customers.

Franchised Electric had recorded approximately $1.4 billion of regulatory assets and $1.9 billion of regulatory liabilities as of December 31, 2004 and December 31, 2003. Management estimates that current rates are sufficient to recover the recorded regulatory assets, in addition to providing a reasonable return for shareholders. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. This assessment reflects the current political and regulatory climate in the states in which Franchised Electric operates, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. The majority of these regulatory assets, including deferred debt expense and the regulatory asset related to income taxes, are amortized and recovered over the lives of the related assets/debt instruments.

Fuel costs are reviewed semiannually by the FERC. The NCUC and PSCSC review fuel costs in rates annually and during general rate case proceedings. All jurisdictions allow Franchised Electric to adjust electric rates for past over- or under-recovery of fuel costs. The difference between actual fuel costs incurred for electric operations and fuel costs recovered through rates is reflected in revenues.

In September 2004, the PSCSC approved Duke Power’s proposal for a rate reduction that will lower industrial customers’ electric rates by an average of 2.8 percent for one year beginning October 1, 2004. The rate reduction builds on Duke Power’s efforts to assist the industrial sector in its South Carolina service area by providing financial relief on monthly power bills. Also, the one year rate decrement approved by the PSCSC for all Duke Power retail electric customers in South Carolina effective October 1, 2003, expired on September 30, 2004.

In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide and nitrogen oxides from coal-fired power plants in the state over the next ten years. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). Franchised Electric’s amortization expense related to this clean air legislation totals $326 million from inception, with $211 million recorded in 2004 and $115 million recorded in 2003. As of December 31, 2004, cumulative expenditures totaled $127 million, with $107 million incurred in 2004 and $20 million incurred in 2003, and are included in Net Cash Provided by Operating Activities on the Consolidated Statements of

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Cash Flows. 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 total estimated cost of $1.5 billion be amortized within the rate freeze period.

Bulk Power Marketing Profit Sharing. In June 2004, the NCUC approved Duke Energy’s proposal to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Power generating units at market based rates (BPM Profits). Duke Energy 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 50% of the North Carolina allocation of BPM Profits to be distributed through various public assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum will be used to reduce rates for industrial customers in North Carolina.

In June 2004, Duke Energy informed the PSCSC that it would no longer include BPM Profits in calculating its South Carolina retail jurisdictional rate of return for its quarterly reports to the PSCSC. Duke Energy has since established an unconsolidated entity, Advance SC LLC, a South Carolina limited liability company, to receive 50% of the South Carolina retail allocation of the BPM Profits to be distributed through various public assistance programs, and to support certain education programs that promote economic development, and programs to promote the attraction and retention of industrial customers in Duke Power’s South Carolina service area. Advance SC LLC is managed by a board of directors that will act independently of Duke Energy. The board consists of representatives from Duke Power’s service area, including representatives from industrial customers, educational institutions, governmental and economic development agencies, and Duke Energy. The PSCSC has not addressed the proposed change in reporting BPM Profits. Duke Energy’s sharing proposal does not require PSCSC approval.

The sharing agreement in both states applies to BPM Profits from January 1, 2004 until the earlier of December 31, 2007, or the effective date of any rates approved by the respective commission after a general rate case. Profits that have been or that will be shared (Shared Profits) of $32 million have been recorded in 2004. The Shared Profits were booked as an $18 million decrease to revenues (for the portion related to reduced industrial customers rates) and a $14 million charge to expenses (for the portion related to donations to charitable, educational and economic development programs in North Carolina and South Carolina).

Depreciation and Decommissioning Studies. The operating licenses for Duke Energy’s nuclear units are subject to renewal. In December 2003, Duke Energy was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy was granted renewed operating licenses for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit).

In March 2005, Duke Power filed the results of a depreciation rate study with the NCUC and PSCSC. Duke Power will adopt new depreciation rates for all functions effective January 1, 2005. The study indicates application of the new rates to depreciable plant in service as of January 1, 2005 will result in an immaterial change in depreciation expense in 2005.

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

In October 2004, Duke Power filed the results of a funding study for nuclear decommissioning costs with the NCUC and in December 2004, Duke Power notified the PSCSC of the results of the funding study. (For further information see Note 7.)

Regional Transmission Organizations (RTOs). The FERC continues to advocate for independent functioning of transmission grids, including through a variety of rulemakings and policy proposals, and has supported the development of Regional Transmission Organizations (RTOs) across the U.S. As a result of these rulemakings, Duke Power and the franchised electric units of Carolina Power & Light Company (now Progress Energy Carolinas) and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies’ combined transmission systems. As of December 31, 2004 and 2003, Duke Energy had invested $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. Due to regulatory uncertainty, development of the GridSouth implementation project was suspended in 2002. Duke Energy continues to examine options in support of FERC’s transmission policy goals. Management expects it will recover its investment in GridSouth.

Natural Gas Transmission. Rate Related Information. The British Columbia Pipeline System (BC Pipeline) and the field services business in western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $612 million as of December 31, 2004 and $543 million as of December 31, 2003. Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.

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When evaluating the recoverability of the BC Pipeline and the field services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and the field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.

In November 2004, the NEB approved 2005 interim tolls for BC Pipeline to be effective January 1, 2005. BC Pipeline will file an application with the NEB for approval of final 2005 tolls under the 2004 settlement agreement in the first quarter of 2005.

Union Gas Limited (Union Gas) has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recovery 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 costs incurred.

On December 15, 2004 the OEB approved the 2005 rates for Union Gas. The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the benchmark return on equity (ROE) determined through the OEB’s formulaic approach, normalized for weather, will be shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below the allowed ROE. Union Gas filed a Notice of Motion on December 22, 2004 to have the OEB reconsider its decision.

The OEB has proposed changes to the implementation dates for the Gas Distribution Access Rule (GDAR). GDAR provides the means by which gas vendors access gas distribution systems in Ontario. Union Gas was granted leave to appeal the vendor consolidated billing provisions of GDAR by the Court of Appeal for Ontario. On January 11, 2005, the Court of Appeal for Ontario dismissed the appeal. The OEB has proposed to defer the implementation of specific sections of the GDAR and to exempt gas distributors from the vendor consolidated billing provisions of the GDAR, subject to any person applying for the OEB to end the exemption.

Maritimes & Northeast Pipeline L.L.C. filed a rate case with the FERC on June 30, 2004 seeking an increase in rates from $0.695 per dekatherm (Dth) to $1.07/Dth. A FERC order accepted the rate filing and suspended the rates until January 1, 2005, when they became effective, subject to refund. The rate case has been set for hearing in 2005. Settlement discussions are ongoing.

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.

International Energy. Brazil Regulatory Environment. In 2004, a new energy law was enacted in Brazil that changed the electricity sector’s regulatory framework. The new energy law created a regulated and non-regulated market that will coexist. The regulated market consists of auctions conducted by the government for the sale of power to the distribution companies. The distribution companies are required to fully contract their estimated electricity demand, principally through these regulated auctions. In the non-regulated market, generators, traders and non-regulated customers are permitted to enter into bilateral electricity purchase and sale contracts. The first regulated auction was held on December 7, 2004. In this auction, distribution companies contracted for their estimated demand for the period from 2005 to 2014. The contract structure within the auction process consisted of eight-year contracts with delivery periods commencing in each of the years 2005, 2006 and 2007. Duke Energy’s Brazilian affiliate, Duke Energy International, Geracao Paranapanema S.A., participated in this auction as a seller of electricity and was awarded eight-year contracts for delivery of 214 MW beginning in 2005, 58 MW for delivery beginning in 2006, and 218 megawatts (MW) for delivery beginning in 2007. During 2005, Duke Energy’s Brazilian affiliate may participate in the next regulated auction for the sale of power to the distribution companies. The auction process provides for eight year contracts with delivery commencing in 2008 and 2009.

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5. Joint Ownership of Generating Facilities

Joint Ownership of Catawba Nuclear Station^(a)

Owner	Ownership Interest
North Carolina Municipal Power Agency Number 1	37.5	%
North Carolina Electric Membership Corporation	28.1	%
Duke Energy Corporation	12.5	%
Piedmont Municipal Power Agency	12.5	%
Saluda River Electric Cooperative, Inc.	9.4	%
	100.0	%

(a) Facility operated by Duke Energy

As of December 31, 2004, $561 million of property, plant and equipment and $295 million of accumulated depreciation and amortization represented Duke Energy’s undivided interest in Catawba Nuclear Station Units 1 and 2. Duke Energy’s share of revenues and operating costs is included in the Consolidated Statements of Operations. As of December 31, 2003, $564 million of property, plant and equipment and $291 million of accumulated depreciation and amortization represented Duke Energy’s undivided interest in Catawba Nuclear Station Units 1 and 2.

Contractual agreements to purchase declining percentages of the station’s generating capacity and energy through the year 2000 made purchased capacity costs subject to rate levelization and deferral. For the North Carolina jurisdiction, all deferred costs were fully recovered as of June 30, 2004. The cost of capacity purchased but not reflected in rates for the North Carolina jurisdiction was $103 million as of December 31, 2003 and was included in Other Current Assets and Other Regulatory Assets and Deferred Debits on the December 31, 2003 Consolidated Balance Sheet. In the South Carolina rate jurisdiction, Duke Energy is currently overcollected on purchased capacity costs. The amount of the overcollection is included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. The liability related to the South Carolina jurisdiction was $135 million as of December 31, 2004 and $146 million as of December 31, 2003. Duke Energy is currently reducing the liability amounts annually through a rate decrement.

6. Income Taxes

The following details the components of income tax expense (benefit) from continuing operations:

Income Tax Expense (Benefit) from Continuing Operations

	For the Years Ended December 31,
	2004			2003			2002
	(in millions)
Current income taxes
Federal	$	(58	)	$	(178	)	$	133
State		34			(42	)		9
Foreign		84			127			19
Total current income taxes		60			(93	)		161
Deferred income taxes
Federal		504			30			313
State		(63	)		(6	)		22
Foreign		43			(13	)		32
Total deferred income taxes		484			11			367
Investment tax credit amortization		(11	)		(12	)		(14	)
Total income tax expense (benefit) from continuing operations	$	533		$	(94	)(a)	$	514

(a) Excludes $94 million of deferred federal, state and foreign tax benefits related to the cumulative effect of changes in accounting principles recorded net of tax.

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The taxes recorded for discontinued operations are excluded from the continuing operations section above and are presented as a separate column in Note 13.

Earnings (Loss) from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2004			2003			2002
	(in millions)
Domestic	$	1,327		$	(368	)	$	1,381
Foreign		458			345			278
Total income (loss)	$	1,785		$	(23	)	$	1,659
Reconciliation of Income Tax Expense (Benefit) at the US Federal Statutory Tax Rate to the Actual Tax Expense (Benefit) from Continuing Operations (Statutory Rate Reconciliation)
	For the Years Ended December 31,
	2004			2003			2002
	(in millions)
Income tax expense (benefit), computed at the statutory rate of 35%	$	625		$	(8	)	$	581
State income tax, net of federal income tax effect		(19	)		(31	)		20
Tax differential on foreign earnings		(33	)		(7	)		(46	)
Employee stock ownership plan dividends		(19	)		(20	)		(33	)
US tax on repatriation of foreign earnings		36			—			—
Other items, net		(57	)		(28	)		(8	)
Total income tax expense (benefit) from continuing operations	$	533		$	(94	)	$	514
Effective tax rate		29.9	%		408.7	%		31.0	%

During 2004, Duke Energy recorded a $52 million income tax benefit from the reduction of state and federal income tax reserves based on the resolution in the second quarter of 2004 of several tax issues. The $52 million benefit is included in the Statutory Rate Reconciliation as follows: a $39 million state benefit is included in “State income tax, net of federal income tax effect” and a $13 million federal benefit is included in “Other items, net”.

During 2004, Duke Energy recorded a $20 million income tax benefit from the change in state tax rates relating to deferred taxes as a result of a reorganization of certain subsidiaries. The $20 million benefit is included in “State income tax, net of federal income tax effect” in the Statutory Rate Reconciliation.

During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of foreign earnings that is anticipated to occur during 2005 related to the American Jobs Creation Act of 2004. The $45 million is included in the Statutory Rate Reconciliation as follows: Federal income taxes of $36 million are included in “US tax on repatriation of foreign earnings”, $4 million of state taxes are included in “State income tax, net of federal income tax effect”, and $5 million of foreign taxes are included in “Tax differential on foreign earnings”.

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Net Deferred Income Tax Liability Components

	December 31,
	2004			2003
	(in millions)
Deferred credits and other liabilities	$	1,334		$	1,190
Other		297			38
Total deferred income tax assets		1,631			1,228
Valuation allowance		(38	)		(39	)
Net deferred income tax assets		1,593			1,189
Investments and other assets		(990	)		(985	)
Accelerated depreciation rates		(4,291	)		(3,006	)
Regulatory assets and deferred debits		(1,167	)		(1,059	)
Total deferred income tax liabilities		(6,448	)		(5,050	)
Total net deferred income tax liabilities	$	(4,855	)	$	(3,861	)

The above amounts have been classified in the Consolidated Balance Sheets as follows:

Deferred Tax Liabilities

	December 31,
	2004			2003
	(in millions)
Current deferred tax assets, included in other current assets	$	217		$	62
Non-current deferred tax assets, included in other investments and other assets		159			197
Current deferred tax liabilities, included in other current liabilities		(3	)		—
Non-current deferred tax liabilities		(5,228	)		(4,120	)
Total net deferred income tax liabilities	$	(4,855	)	$	(3,861	)

As of December 31, 2004, Duke Energy has a net operating loss carryforwards of $274 million relating to federal income taxes which expire in the year 2024 and $61 million relating to state income taxes which mostly expire in years 2019 and later.

Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. The net change in the total valuation allowance is included in “Tax differential on foreign earnings” and “State income tax, net of federal income tax effect” lines of the Statutory Rate Reconciliation.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income and other taxes have been made for potential liabilities resulting from such matters. As of December 31, 2004, Duke Energy has total provisions for uncertain tax positions of approximately $149 million as compared to $254 million as of December 31, 2003, which includes interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

Deferred income taxes and foreign withholding taxes of $45 million have been recorded in the fourth quarter of 2004 on approximately $500 million of earnings relating to Duke Energy’s foreign subsidiaries that are anticipated to be remitted in 2005 as dividends relating to the American Jobs Creation Act of 2004. Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Duke Energy’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2004 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes, is approximately $150 million.

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7. Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Asset retirement obligations at Duke Energy relate primarily to the decommissioning of nuclear power facilities, the retirement of certain gathering pipelines and processing facilities, the retirement of some gas-fired power plants, obligations related to right-of-way agreements and contractual leases for land use.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

In accordance with SFAS No. 143, Duke Energy identified certain assets that have an indeterminate life, and thus a future retirement obligation is not determinable. These assets included on-shore and some off-shore pipelines, certain processing plants and distribution facilities and some gas-fired power plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

Upon adoption of SFAS No. 143, Duke Energy’s regulated electric and regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $982 million as of December 31, 2004, which consisted of $966 million related to regulated electric operations and $16 million related to regulated natural gas operations. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $1,207 million as of December 31, 2003, which consisted of $1,190 million related to regulated electric operations and $17 million related to regulated natural gas operations.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by Duke Energy on January 1, 2003. As of January 1, 2003, the implementation of SFAS No. 143 resulted in a net increase in total assets of $863 million, consisting primarily of an increase in net property, plant and equipment of $213 million and an increase in regulatory assets of $650 million. Liabilities increased by $874 million, primarily representing the establishment of an asset retirement obligation liability of $1,599 million, reduced by the amount that was already recorded as a nuclear decommissioning liability of $708 million. Substantially all of the obligations are related to Duke Energy’s regulated electric operations. The adoption of SFAS No. 143 had no impact on the income of the regulated electric operations, as the effects were offset by the establishment of a regulatory asset pursuant to SFAS No. 71. Duke Energy has received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143. For obligations related to non-regulated operations, a net-of-tax cumulative effect of a change in accounting principle adjustment of $11 million was recorded in the first quarter of 2003 as a reduction in earnings.

The pro forma net income and related basic and diluted earnings per share effects of adopting SFAS No. 143 are not shown due to their immaterial impact.

The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Reconciliation of Asset Retirement Obligation Liability

	Years Ended December 31,
	2004			2003
	(in millions)
Balance as of January 1,	$	1,707		$	1,599
Liabilities incurred due to new acquisitions		8			—
Liabilities settled		(2	)		(7	)
Accretion expense		125			111
Revisions in estimated cash flows		86			(2	)
Foreign currency adjustment		2			6
Balance as of December 31,	$	1,926		$	1,707

Accretion expense for the year ended December 31, 2004 included approximately $120 million related to Duke Energy’s regulated electric operations and has been deferred as a regulatory asset in accordance with SFAS No. 71 as discussed above. Accretion expense for the year ended December 31, 2003 included approximately $106 million related to Duke Energy’s regulated electric operations and has also been deferred as a regulatory asset in accordance with SFAS No. 71. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,082 million as of December 31, 2004 and $925 million as of December 31, 2003.

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Revisions in estimated cash flows changed significantly during 2004 due primarily to the new nuclear decommissioning study performed during the year at Franchised Electric. As a result of that study, it was determined that more nuclear obligations existed and as such, the additional liability was recorded.

Nuclear Decommissioning Costs. In 2003, an internal reserve, which is contained in the accumulated depreciation balance on the Consolidated Balance Sheets and external funds, presented on the Consolidated Balance Sheets as the NDTF for decommissioning were maintained separately for contaminated and non-contaminated components. These external funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents and were recorded at their fair value in the Consolidated Balance Sheets. Per the regulation or mandates of one or more entities including the Nuclear Regulatory Commission (NRC), PSCSC, NCUC, and Internal Revenue Service, these funds may be used only for activities related to nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear decommissioning recognizes that costs are recovered through Franchised Electric’s rates, fluctuations in equity prices or interest rates do not affect consolidated results of operations or cash flows. (See Note 1, Other Long-term Investments and Note 9 for additional information.)

On February 5, 2004, the NCUC issued an order requiring Duke Energy to transition the internal reserve to the NDTF over a ten-year period, beginning on January 1, 2008, with the annual transfer level at a minimum of 10% of the North Carolina internal reserve as of December 31, 2007, and with the actual transfer of funds occurring no later than December 31 of each calendar year beginning in 2008. The NCUC also ordered that as of December 31, 2007, there shall be no further funding of internal reserve and all future decommissioning requirements must be fully funded through the NDTF.

During 2004, Duke Energy expensed approximately $70 million and contributed approximately $70 million of cash to the NDTF for decommissioning costs; these amounts are presented in the Consolidated Statements of Cash Flows in Other within Cash Flows from Investing Activities. Pursuant to the February 5, 2004 NCUC order in April 2004, $262 million reserved for non-contaminated costs was contributed in cash, to the NDTF; these amounts are also presented in the Consolidated Statements of Cash Flows in Other within Cash Flows from Investing Activities. During 2003, Duke Energy expensed approximately $56 million, and contributed $56 million of cash to the NDTF for decommissioning costs, and accrued an additional $11 million to the internal reserve. Nuclear units are currently depreciated at an annual rate of 4.7%, of which 1.61% is for decommissioning. The balance of the external funds was $1,374 million as of December 31, 2004 and $925 million as of December 31, 2003. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset).

In October 2004, Duke Power filed the results of a funding study for nuclear decommissioning costs with the NCUC, and in December 2004, Duke Power notified the PSCSC of the results of the funding study (filing of the study is not required by the PSCSC). The funding study, which was based on the updated nuclear decommissioning cost estimate and renewal of the nuclear operating licenses, indicates that an annual cash contribution to the NDTF of $48 million (compared to a current level of approximately $70 million) is now required to fully cover the estimated nuclear decommissioning costs. Duke Power anticipates that the NCUC will rule later in 2005 on whether any change in Duke Power’s decommissioning expense is necessary.

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. The previous study, conducted in 1999, estimated a decommissioning cost of $1.9 billion ($2.2 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning). Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.

The operating licenses for Duke Energy’s nuclear units are subject to extension. In December 2003, Duke Energy was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy was granted a license renewal for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit).

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Current Operating Licenses for Duke Energy’s Nuclear Units

Unit	Expiration Year
McGuire 1	2041
McGuire 2	2043
Catawba 1	2043
Catawba 2	2043
Oconee 1 and 2	2033
Oconee 3	2034

To reflect the impact on the nuclear decommissioning asset retirement obligation resulting from the renewed operating licenses and the change in estimated decommissioning costs, the asset retirement obligation was increased by $109 million in 2004. Additionally, due in part to the renewal of the nuclear operating licenses, Franchised Electric conducted a depreciation rate study. In March 2005, Duke Power filed the results of a depreciation rate study with the NCUC and PSCSC. Duke Power adopted new depreciation rates for all functions effective January 1, 2005. The study indicates application of the new rates to depreciable plant in service as of January 1, 2005 will result in an immaterial change in depreciation expense in 2005.

A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE’s uranium enrichment plants (the D&D Fund). Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. Lawsuits filed by Duke Energy and other utilities challenging the constitutionality of the D&D Fund have been dismissed. The annual assessment is recorded in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. Duke Energy has paid $129 million into the fund, including $11 million each year during 2004, 2003 and 2002. The remaining liability and regulatory assets of $23 million as of December 31, 2004 and $33 million as of December 31, 2003 are reflected in the Consolidated Balance Sheets as Deferred Credits and Other Liabilities, and Regulatory Assets and Deferred Debits.

8. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments

Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.

Duke Energy’s Derivative Portfolio Carrying Value as of December 31, 2004

Asset/(Liability)	Maturity in 2005			Maturity in 2006			Maturity in 2007			Maturity in 2008 and Thereafter			Total Carrying Value
	(in millions)
Hedging	$	167		$	294		$	167		$	173		$	801
Trading		47			21			(5	)		(9	)		54
Undesignated		(71	)		(52	)		(49	)		(132	)		(304	)
Total	$	143		$	263		$	113		$	32		$	551

The amounts in the table above represent the combination of amounts presented as assets and (liabilities) for Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions on Duke Energy’s Consolidated Balance Sheets. All amounts in the table represent fair value except that certain hedging amounts include assets related to the application of the normal purchases and normal sales exception for electricity contracts of $160 million as of December 31, 2004. Duke Energy began applying the normal purchases and normal sales exception of DIG Issue C15 for electricity contracts July 1, 2001. For those contracts that were previously designated as cash flow hedges, Duke Energy treated the change as a de-designation under SFAS No. 133, and the fair value of each qualifying contract on July 1, 2001 became the contract’s net carrying amount. The contract’s net carrying amount will reduce upon settlement of the associated contracts over the next six years.

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Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Energy is hedging exposures to the price variability of these commodities for a maximum of 13 years.

The ineffective portion of commodity cash flow hedges resulted in a gain of $3 million in 2004, a gain of $7 million in 2003, and a loss of $10 million in 2002, pre-tax, and is reported in the Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other line item on the Consolidated Statement of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges was not material in 2004 or 2002 and was a gain of $285 million in 2003, pre-tax. Approximately $130 million of the 2003 disqualified cash flow hedges was primarily associated with power hedges related to DENA’s partially completed plants and is included in Discontinued Operations (see Note 13). The remainder of the 2003 disqualified cash flow hedges was primarily associated with gas hedges related to DENA’s Southeast Plants.

As of December 31, 2004, $311 million of the pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges that were accumulated on the Consolidated Balance Sheet in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

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. For 2004, 2003, and 2002 the ineffective portion of commodity fair value hedges was reported in the Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other line item on the Consolidated Statement of Operations and was not material. The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2004 or 2002 and was a loss of $582 million, pre-tax, in 2003. The loss recorded in 2003, which primarily included amounts for certain contracts that were being accounted for as normal purchases and sales, was recognized primarily due to management’s intent for DENA’s partially completed plants, and was included in Discontinued Operations (see Note 13).

Normal Purchases and Normal Sales Exception. Duke Energy has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133 and interpreted by DIG Issue C15, to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 11 years, are not included in the table above. As discussed in the preceding paragraph, a portion of the charge in DENA in 2003 related to contracts that were being accounted for as normal purchases and sales. See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy to risk as a result of its issuance of variable-rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Energy’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2004, 2003, and 2002.

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. During 2004, $43 million of net losses were included in the cumulative translation adjustment for hedges of net investments in foreign operations. During 2003, a $113 million net loss was included in the cumulative translation adjustment for hedges of net investments in foreign operations. During 2002, a $4 million net loss was included in the cumulative translation adjustment for hedges of net investments in foreign operations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

Other Derivative Contracts. Trading. Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of proprietary trading activities. During 2003, Duke Energy prospectively discontinued proprietary trading and therefore the fair value of trading contracts as

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of December 31, 2004 relates to contracts entered into prior to the announced discontinuation of proprietary trading activities. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

Undesignated. In addition, Duke Energy uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the normal purchase and normal sales scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category are primarily associated with forward power sales for the DENA Southeast Plants and partially completed plants which were disqualified in 2003.

Credit Risk. 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.

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and marketing and risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and generally covers trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy and its affiliates.

The change in market value of New York Mercantile Exchange (NYMEX)-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.

Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Financial Instruments. The fair value of financial instruments not currently carried at market value is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2004 and 2003, are not necessarily indicative of the amounts Duke Energy could have realized in current markets.

Financial Instruments

	Years Ended December 31,
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	2004				2003
	(in millions)
Long-term debt(a)	$	18,764	$	20,448	$	21,822	$	23,554
Preferred stock		134		133		134		135

(a) Includes current maturities.

The fair value of cash and cash equivalents, notes and accounts receivable, notes and accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.

9. Marketable Securities

Short-term investments. At December 31, 2004 and 2003 Duke Energy had $1,319 million and $763 million, respectively of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are

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classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2004, Duke Energy purchased approximately $63,879 million and received proceeds on sale of approximately $63,323 million of short-term investments. During 2003, Duke Energy purchased approximately $38,908 million and received proceeds on sale of approximately $38,638 million of short-term investments. During 2002, Duke Energy purchased approximately $11,920 million and received proceeds on sale of approximately $11,427 million.

Other Long-term investments. Duke Energy also invests in debt and equity securities that are held in the NDTF (see Note 4 for further information on the nuclear decommissioning trust funds) and the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified long-term as management does not intend to use them in current operations. Duke Energy’s NDTF ($1,374 million at December 31, 2004) consists of approximately of 68% equity securities, 30% debt securities, and 2% cash and cash equivalents with a weighted average maturity of the debt securities of approximately 8 years. Duke Energy’s captive insurance investment portfolio ($185 million at December 31, 2004) consists of approximately 66% debt securities, 21% cash and cash equivalent and 13% equity securities with a weighted average maturity of the debt securities of approximately 8 years. The cost of securities sold is determined using the specific identification method.

The estimated fair values of long-term investments classified as available-for-sale are as follows (in millions):

	As of December 31,
	2004						2003
	Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value
Equity Securities	$	261	$	17	$	960	$	181	$	20	$	657
Corporate Debt Securities		1		—		40		1		—		50
Municipal Bonds		3		—		193		4		—		66
U.S. Government Bonds		14		1		252		13		—		266
Other		1		—		114		1		—		122
Total	$	280	$	18	$	1,559	$	200	$	20	$	1,161

For the years ended December 31, 2004, 2003, and 2002 gains of approximately $3 million, $4 million and $4 million, respectively, were reclassified out of AOCI into earnings.

The following table provides the realized gains and losses, as well as gross proceeds from sale and gross purchases of the captive insurance investment portfolio (in millions):

Years Ended December 31,	2004		2003		2002
Realized Gains	$	6	$	9	$	4
Realized Losses		3		5		3
Proceeds from sale of securities		769		1,003		432
Purchases of securities		715		1,124		473

Duke Energy contributed approximately $329 million in 2004 and $56 million in 2003 and 2002 to the NDTF. These contributions are presented in Other within Cash Flows From Investing Activities on the Consolidated Statements of Cash Flows. Realized and unrealized gains and losses on sales of investments within the NDTF are recorded in Other within Regulatory Assets and Deferred Debits and Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

10. Goodwill

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142. As a result of the annual impairment tests required by SFAS No. 142, no charge for the impairment of goodwill was recorded in 2004.

In 2003, Duke Energy recorded a goodwill impairment charge of $254 million to write off all DENA goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Energy used a discounted cash flow analysis to determine fair value. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporated current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices. This charge is recorded in the Consolidated Statements of Operations as Impairment of Goodwill.

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In 2002, Duke Energy recorded a goodwill impairment charge of $194 million related to International Energy’s European trading and gas marketing business (European Business), substantially all of which was sold in the fourth quarter of 2003. Significant changes in the European market and operating results adversely affected Duke Energy’s outlook for this reporting unit. The exit of key market participants and a tightening of credit requirements were the primary drivers of this revised outlook. The fair value of the European reporting unit was estimated using a discounted cash flow analysis, which included key assumptions including the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporated current market information, historical factors and fundamental analysis, and other factors in determining estimated future cash flows. This charge is recorded in the Consolidated Statements of Operations in Discontinued Operations—Net Operating Loss, net of tax. See Note 13 for further information regarding the European reporting unit and its treatment as discontinued operations in the Consolidated Statements of Operations.

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2003		Impairments			Dispositions			Other(a)			Balance December 31, 2004
	(in millions)
Natural Gas Transmission	$	3,241	$	—		$	—		$	175		$	3,416
Field Services		476		—			—			4			480
International Energy		238		—			—			7			245
Crescent		7		—			—			—			7
Total consolidated	$	3,962	$	—		$	—		$	186		$	4,148
	Balance December 31, 2002		Impairments			Dispositions(c)			Other(a)			Balance December 31, 2003
	(in millions)
Natural Gas Transmission	$	2,774	$	—		$	(27	)	$	494		$	3,241
Field Services		467		—			—			9			476
DENA		100		(100	)		—			—			—
International Energy		246		—			(5	)		(3	)		238
Crescent		6		—			—			1			7
Other(b)		154		(154	)		—			—			—
Total consolidated	$	3,747	$	(254	)	$	(32	)	$	501		$	3,962

(a) Amounts consist primarily of foreign currency translation and purchase price adjustments to prior year acquisitions.

(b) Amount represents corporate goodwill that is allocated to DENA for the purpose of impairment testing pursuant to SFAS No. 142. As a result, the impairment charge in 2003 was recorded in the DENA segment.

(c) Amounts were included in the disposal of a portion of a reporting unit within Natural Gas Transmission and International Energy.

11. Investments in Unconsolidated Affiliates and Related Party Transactions

Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Duke Energy received distributions of $139 million in 2004, $263 million in 2003, and $369 million in 2002 from those investments. These amounts are included in Other, assets within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. Duke Energy’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates or as Discontinued Operations. (See Note 2 for 2004 dispositions.)

As of December 31, 2004 and December 31, 2003, investments in affiliates were carried at approximately $91 million and $66 million, respectively, less than the amount of underlying equity in net assets (7% of total investment in affiliates as of December 31, 2004 and 5% as of December 31, 2003). This amount is related to the difference in the carrying amount and the underlying net assets of investments owned by Field Services. Such difference has been fully allocated to the respective investee’s long-lived assets and the amounts are being amortized into income over the life of the underlying related long-lived assets.

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Natural Gas Transmission. As of December 31, 2004 investments primarily included a 50% interest in Gulfstream Natural Gas System, LLC (Gulfstream). Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although Duke Energy owns a significant portion of Gulfstream, it is not consolidated as Duke Energy does not hold a majority of voting control or have the ability to exercise control over Gulfstream.

Field Services. As of December 31, 2004 investments primarily included a 33% interest in Discovery Producer, LLC, a natural gas gathering and processing system that includes a pipeline in the Gulf of Mexico and natural gas processing and fractionation facilities in Louisiana. As of December 31, 2004 Field Services also owned Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners, L.P. (TEPPCO), a publicly traded master limited partnership which owns and operates a network of pipelines, storage and terminal facilities for refined products, liquefied petroleum gases, petrochemicals, natural gas and crude oil. The general partner is responsible for the management and operations of TEPPCO. See Note 23 for subsequent events disclosure.

DENA. As of December 31, 2004 investments primarily included a 50% interest in Southwest Power Partners, LLC. Southwest Power Partners, LLC is a gas-fired combined-cycle facility in Arizona that serves markets in Arizona, Nevada and California. Although Duke Energy owns a significant portion of this investment, it is not consolidated as it does not hold a majority of voting control or have the ability to exercise control over this investment. Southwest Power Partners, LLC is a component of DENA’s western United States generation assets that qualify for discontinued operations classification for current and prior periods (see Note 13). As a result, earnings or losses from this investment are classified as Discontinued Operations in the accompanying Consolidated Statements of Operations.

International Energy. As of December 31, 2004 investments primarily included a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE (methyl tertiary butyl ether) business in Jubail, Saudi Arabia. International Energy also has a 50% ownership in Compañia 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, and a 38% ownership in Aguaytia, a natural gas facility in Peru.

Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. Campeche has made a renewal offer to PEMEX that has been initially rejected; however, discussions continue with PEMEX regarding renewal of the contract or other possible arrangements. If it is determined that the renewal will not take place or another economically viable arrangement is not found, the value of International Energy’s equity investment in Campeche would decline and such investment would be written down to its resulting fair value. International Energy’s estimated maximum exposure to this risk is potential impairment or other charges of $70 million.

Crescent. As of December 31, 2004 investments included various real estate development projects.

Other. As of December 31, 2004 investments primarily included participation in various construction and support activities for fossil-fueled generating plants through D/FD.

Investments in Unconsolidated Affiliates

	As of:
	December 31, 2004						December 31, 2003
	Domestic		International		Total		Domestic		International		Total
	(in millions)
Natural Gas Transmission	$	769	$	21	$	790	$	787	$	24	$	811
Field Services		157		—		157		194		—		194
DENA		134		—		134		139		20		159
International Energy		—		167		167		—		147		147
Crescent		20		—		20		15		—		15
Other		17		7		24		66		6		72
Total	$	1,097	$	195	$	1,292	$	1,201	$	197	$	1,398

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Equity in Earnings of Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2004						December 31, 2003									December 31, 2002
	Domestic		International		Total		Domestic			International			Total			Domestic			International			Total
	(in millions)
Natural Gas Transmission	$	26	$	4	$	30	$	19		$	13		$	32		$	87		$	19		$	106
Field Services		60		—		60		56			—			56			60			—			60
DENA(b)		—		—		—		22			(7	)		15			39			5			44
International Energy		—		51		51		—			27			27			—			63			63
Crescent		3		—		3		—			—			—			—			—			—
Other(a)		16		1		17		(9	)		2			(7	)		(54	)		(1	)		(55	)
Total	$	105	$	56	$	161	$	88		$	35		$	123		$	132		$	86		$	218

(a) Includes equity investments at the corporate level and the elimination of 50% of the profit earned by D/FD on construction projects with DENA and Duke Power. D/FD is 50% owned by Duke Energy. See additional information in the Related Party Transactions section that follows.

(b) Losses from unconsolidated affiliates of $14 million in 2002 were included in Discontinued Operations in the Consolidated Statements of Operations. No earnings or losses from unconsolidated affiliates were included in Discontinued Operations for 2003 or 2004.

Summarized Combined Financial Information of Unconsolidated Affiliates

	As of December 31,
	2004			2003
	(in millions)
Balance Sheet
Current assets	$	1,413		$	1,552
Noncurrent assets		6,028			8,435
Current liabilities		(1,118	)		(979	)
Noncurrent liabilities		(2,078	)		(4,062	)
Net assets	$	4,245		$	4,946

	For the Years Ended December 31,
	2004		2003		2002
	(in millions)
Income Statement
Operating revenues	$	7,326	$	6,253	$	6,072
Operating expenses		6,872		5,526		5,094
Net income		415		550		830

Related Party Transactions. Outstanding notes receivable from unconsolidated affiliates were $89 million as of December 31, 2004 and $146 million as of December 31, 2003. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. Of the notes outstanding as of December 31, 2004, $50 million related to International Energy’s note receivable from the Campeche project, a 50% owned joint venture, $25 million related to a note from a partnership in which Natural Gas Transmission has 50% ownership, and the remaining $14 million related to notes that Crescent had with partners in three of its joint ventures. These outstanding notes receivables had interest rates at or above current market rates.

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International Energy loaned money to Campeche to assist in the costs to build. During 2004, International Energy received principal and interest payments of $7 million from Campeche, a 50% owned DEI affiliate. Payments from Campeche in 2003 and 2002 were $8 million and $1 million, respectively.

Natural Gas Transmission has a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline. In addition, Natural Gas Transmission has a 50% interest in a power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility. Natural Gas Transmission provides certain administrative and other services to the pipeline companies and the power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $8 million, $12 million, and $14 million during 2004, 2003, and 2002, respectively. The outstanding receivable from these affiliates was $1 million and $2 million for 2004 and 2003, respectively.

Firm capacity payments to Alliance Pipeline and Vector Pipeline were $33 million and $30 million for 2003 and 2002, respectively. Natural Gas Transmission sold its ownership in these pipelines in 2003.

During 2002, Natural Gas Transmission recognized $28 million in earnings for a construction fee received from an unconsolidated affiliate related to the successful completion of Gulfstream.

Advance SC LLC, which provides funding for economic development projects, educational initiatives, and other programs, was formed during 2004. Duke Power made a $6.5 million donation to the nonconsolidated subsidiary during the year.

Field Services sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services to unconsolidated affiliates (primarily TEPPCO). Total revenues from these affiliates were approximately $278 million, $166 million, and $138 million for 2004, 2003, and 2002, respectively. Total purchases from these affiliates were approximately $125 million, $98 million, and $82 million for 2004, 2003, and 2002, respectively. Total operating expenses were $4 million for 2004 and 2003 and $1 million for 2002.

D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD was the primary builder of DENA’s merchant generation plants. D/FD has built some plants for Duke Power. Fifty percent of the profit earned by D/FD for the construction of affiliates’ generation plants, which is associated with Duke Energy’s ownership, is either deferred in consolidation until the plant is sold or, once the plant becomes operational, the deferred profit is amortized over the plant’s useful life or on an accelerated basis if the plants are impaired. Fifty percent of the profit earned by D/FD for operating and maintenance services for Duke Energy owned plants is eliminated in consolidation. For the year ended December 31, 2004, Duke Energy deferred profit of $2 million for D/FD construction contracts and did not eliminate any profit for operating and maintenance services. For the year ended December 31, 2003, Duke Energy deferred profit of $59 million for construction contracts and eliminated profit of less than one million for operating and maintenance services. For the year ended December 31, 2002, Duke Energy deferred profit of $159 million for construction contracts and eliminated profit of $3 million for operating and maintenance services. In addition, as part of the D/FD partnership agreement, excess cash is loaned at current market rates to Duke Energy and Fluor Enterprises, Inc. (See Note 15.)

In the normal course of business, Duke Energy’s consolidated subsidiaries enter into energy trading contracts or other derivatives with one another. On a separate company basis, each subsidiary accounts for such contracts as if they were transacted with a third party and records the contracts using the MTM Model or the Accrual Model of Accounting (Accrual Model), as applicable. For example, DETM may enter into a contract to purchase natural gas from DEFS. DEFS may record this contract using accrual accounting, while DETM may mark the contract to market through its current earnings. In the consolidation process, the effects of this intercompany contract are eliminated, and not reflected in Duke Energy’s Consolidated Financial Statements.

Also see Note 15, Debt and Credit Facilities, Note 17, Commitments and Contingencies, and Note 18, Guarantees and Indemnifications, and Note 23, Subsequent Events, for additional related party information.

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12. Impairment, Severance, and Other Related Charges

The following amounts were recorded in the Consolidated Statements of Operations as Impairments and Other Related Charges. See also Note 13 for impairments and other charges recorded in Discontinued Operations in the Consolidated Statement of Operations.

	For the Years Ended December 31,
	2004		2003		2002
	(in millions)
Duke Energy North America	$	—	$	1,166	$	156
Field Services		22		—		78
International Energy		—		—		75
Crescent		42		—		—
Other		—		53		4
Total Impairment and other related charges	$	64	$	1,219	$	313

Field Services. In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to some of Field Services’ operating assets. The majority of this charge relates to the MBPP exchange transaction discussed in Note 2.

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

The 2002 charges were primarily to write-off inventory and other current assets to their net realizable value.

Crescent. In the fourth quarter of 2004, Crescent recorded impairment charges of approximately $42 million related to two residential developments in Payson, Arizona, the Rim and Chaparral Pines, and one residential development in Austin, Texas, Twin Creeks. The impairment charges were related to long lived assets at the three properties. The developments have suffered from slower than anticipated absorption of available inventory. Fair value of the assets was determined based on management’s assessment of current operating results and discounted future cash flow models. Crescent also recorded bad debt charges of $8 million related to notes receivable due from Rim Golf Investor, LLC and Chaparral Pines Investor, LLC. This amount is recorded in Operation, Maintenance and Other on the Consolidated Statement of Operations.

DENA. In the fourth quarter of 2003, as a result of deteriorating market conditions in the merchant energy industry, Duke Energy decided to exit the merchant power generation business in the Southeastern U.S. The carrying value of the Southeast Plants exceeded the fair value, resulting in an impairment charge in 2003 of approximately $1.3 billion. The fair value of the Southeast Plants was estimated primarily based on third party comparable sales, analysis from outside advisors and information available from efforts to sell certain of these assets. These assets were subsequently sold in the second quarter of 2004. (See Note 2.)

DENA recorded additional impairment charges of $60 million in 2003, primarily associated with a plan to sell an investment in Bayside, an unconsolidated affiliate. Fair value of these assets was estimated based primarily on discounted cash flow analysis.

Certain forward power contracts related to the Southeast Plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a benefit of $190 million was recorded as an offset to the impairment charge.

As a result of the decisions discussed above, DENA recorded impairment charges in 2003 of approximately $1.2 billion, primarily related to electric generation plants which are classified as Property, Plant and Equipment on the Consolidated Balance Sheets and to mark the derivative contracts to market value and reclassify the hedge amounts previously included in AOCI in accordance with SFAS No. 133.

The 2002 impairment and other related charges included a partial impairment of uninstalled turbines and the termination of other turbines on order. Additionally, charges were recorded in 2002 to impair an abandoned information technology system. Fair value of these assets was estimated based on comparable sales or discounted cash flow analysis.

International Energy. The 2002 charges were to write-off site development costs in Brazil and Bolivia, and to partially impair uninstalled turbines.

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Other. The 2003 charges were due primarily to the abandonment of a corporate risk management information system, primarily due to DENA exiting the proprietary trading business and the reduction of scope and scale of DETM’s business.

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

Severance Reserve	Balance at January 1, 2004		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2004
	(in millions)
DEI	$	6	$	—	$	(4	)	$	(1	)	$	1
DEFS(c)		6		1		—			(7	)		—
Gas Transmission		29		1		(6	)		(18	)		6
Franchised Electric		60		—		(6	)		(50	)		4
DENA(d)		7		1		(1	)		(6	)		1
Crescent		—		—		—			—			—
Other		42		2		(4	)		(37	)		3
Total(a)	$	150	$	5	$	(21	)	$	(119	)	$	15
	Balance at January 1, 2003		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2003
DEI	$	4	$	6	$	(4	)	$	—		$	6
DEFS(c)		—		6		—			—			6
Gas Transmission		33		20		1			(25	)		29
Franchised Electric		29		65		—			(34	)		60
DENA(d)		14		8		(2	)		(13	)		7
Crescent		—		—		—			—			—
Other		33		29		—			(20	)		42
Total(a)(b)	$	113	$	134	$	(5	)	$	(92	)	$	150
	Balance at January 1, 2002		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2002
DEI	$	5	$	2	$	(2	)	$	(1	)	$	4
DEFS(c)		—		—		—			—			—
Gas Transmission		—		54		(1	)		(20	)		33
Franchised Electric		7		28		(1	)		(5	)		29
DENA(d)		—		26		(12	)		—			14
Crescent		—		—		—			—			—
Other		—		34		—			(1	)		33
Total(a)	$	12	$	144	$	(16	)	$	(27	)	$	113

(a) Substantially all expected severance costs will be applied to the reserves within one year.

(b) Provision in 2003 excludes $22 million of curtailment costs related to other post-retirement benefits.

(c) Includes minority interest.

(d) Severence expense included in Discontinued Operations in the Consolidated Statements of Operations was $1 million, $7 million and $8 million for 2004, 2003 and 2002, respectively.

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13. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations (in millions)

			Operating Income (Loss)									Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax
Year Ended December 31, 2004
Field Services	$	79	$	3		$	1		$	2		$	(17	)	$	(6	)	$	(11	)
DENA		2,299		(194	)		(56	)		(138	)		178			61			117
International Energy		85		(13	)		(1	)		(12	)		295			22			273
Crescent		2		—			—			—			9			4			5
Other		1		2			1			1			1			—			1
Total consolidated	$	2,466	$	(202	)	$	(55	)	$	(147	)	$	466		$	81		$	385
Year Ended December 31, 2003
Field Services	$	345	$	9		$	3		$	6		$	19		$	7		$	12
DENA		4,170		(1,687	)		(613	)		(1,074	)		—			—			—
International Energy		759		(34	)		(4	)		(30	)		(242	)		(119	)		(123	)
Crescent		5		—			—			—			18			7			11
Other		30		(4	)		(1	)		(3	)		(49	)		(18	)		(31	)
Total consolidated	$	5,309	$	(1,716	)	$	(615	)	$	(1,101	)	$	(254	)	$	(123	)	$	(131	)
Year Ended December 31, 2002
Field Services	$	299	$	(23	)	$	(9	)	$	(14	)	$	—		$	—		$	—
DENA		1,223		246			96			150			—			—			—
International Energy		133		(256	)		7			(263	)		—			—			—
Other		57		25			9			16			—			—			—
Total consolidated	$	1,712	$	(8	)	$	103		$	(111	)	$	—		$	—		$	—

Field Services

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

In December 2004, Field Services sold gas system and treating plant assets in Southeast New Mexico and South Texas, respectively. Field Services sold these assets for proceeds of approximately $6 million, with the carrying value being approximately equal to the sales price. The after tax loss and related results of operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

In September 2004, Field Services recorded an impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering, processing, compression and transportation assets in Wyoming. The estimated fair value of these assets less cost to sell was $27 million and classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2004. The after tax loss and related results of operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. In the first quarter of 2005, Field Services sold these assets for proceeds of $28 million, with the carrying value being approximately equal to the sales price.

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

In 2003, Field Services sold two packages of assets for a total sales price of $90 million. The after tax gain on these sales of $12 million and related operating results were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. The assets sold consisted of various gas processing plants and gathering pipelines in Mississippi, Texas, Alabama, Louisiana and Oklahoma.

DENA

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

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

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

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

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

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, as discussed further in Note 2, DENA’s Southeastern generation operations, including related commodity contracts do not qualify for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

For the year ended December 31, 2004, DENA incurred net operating losses on its discontinued operations. DENA’s discontinued operations also included sales and impairments of merchant power plants located in Washington (“Grays Harbor” plant), Nevada (“Moapa” plant) and New Mexico (“Luna” plant) (collectively, the deferred plants). The deferred plants were a component of DENA’s western United States generation assets that qualify for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. Details are as follows:

• The partially completed Moapa facility was sold to Nevada Power Company and resulted in $186 million in net proceeds and a pre-tax gain of approximately $140 million recorded in Discontinued Operations – Net Gain (Loss) on Dispositions, net of tax, in the 2004 Consolidated Statement of Operations.

• The partially completed Luna facility was sold to PNM Resources, Tucson Electric Power and Phelps Dodge Corporation and resulted in net proceeds of $40 million and a pre-tax gain of approximately $40 million recorded in Discontinued Operations – Net Gain (Loss) on Dispositions, net of tax, in the 2004 Consolidated Statements of Operations.

• In December 2004, DENA agreed to sell the partially completed Grays Harbor facility to an affiliate of Invenergy LLC. Also, effective December 31, 2004, Duke Energy terminated its capital lease associated with the dedicated pipeline which would have transported natural gas to the plant. This termination resulted in a $20 million pre-tax charge recorded in Discontinued Operations, net of tax, in the 2004 Consolidated Statement of Operations. In the first quarter of 2005, Grays Harbor was sold, resulting in a pre-tax gain of approximately $21 million (excludes any potential contingent consideration). Total sales proceeds and tax benefits for this transaction, excluding any potential contingent consideration, in 2005 was approximately $116 million. The termination of the capital lease substantially offsets the proceeds and tax benefits from the sale.

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On September 21, 2004 DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving will purchase DENA’s 75% interest in Bayside Power L.P. (Bayside). Irving had the right to terminate the agreement at any time prior to February 21, 2005. Irving did not terminate this agreement within the deadline specified and the terms of the purchase and sale agreement are now binding. Closing will occur upon receipt of required third party consents and regulatory approvals which are expected sometime in the second quarter 2005. As a result of the above agreement, DENA presented the $40 million net assets of Bayside as “held for sale” in the Consolidated Balance Sheets as of December 31, 2004. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was $19 million at December 31, 2004. Bayside was consolidated with the adoption of FIN 46 on March 31, 2004. Therefore, Bayside’s operating results for the period April 1 to December 31, 2004 are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Prior operating results, including the impairment of the investment in Bayside of $55 million recorded in 2003, are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.

For the year ended December 31, 2003, DENA’s net operating loss from discontinued operations was due primarily to the following:

• Impairments of the deferred plants. In the fourth quarter of 2003, Duke Energy decided not to fund completion of construction of three DENA deferred plants. The carrying value of these assets exceeded the fair value, resulting in an impairment charge of approximately $1.1 billion pre-tax ($515 million for Moapa, $270 million for Luna and $362 million for Grays Harbor) which was recorded in Discontinued Operations, net of tax, in the 2003 Consolidated Statement of Operations. The fair value of the deferred plants was estimated based primarily on analysis from outside advisors and information available from efforts to sell certain of these assets.

• Certain forward power contracts related to the deferred plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a pre-tax charge of $452 million was recorded.

• A power generation plant in Maine. During 2003, Duke Energy agreed to sell this plant and recorded a pre-tax impairment charge of $72 million for the portion of the carrying value in excess of the negotiated sales price for the plant. The sale that was anticipated did not occur. This plant was a component of DENA’s eastern United States generation assets that qualify for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations.

• An impairment charge of $64 million in 2003 associated with a change in the expected dispatch of Morro Bay, a plant in California. Fair value of this asset was estimated based primarily on discounted cash flow analysis.

For the year ended December 31, 2002, DENA’s net operating income from discontinued operations included charges to impair one of DENA’s merchant power facilities and write-off site development costs in California. Fair value of these assets was estimated based on comparable sales or discounted cash flow analysis.

Due to the implementation of EITF Issue No. 02-03 on January 1, 2003, the accounting for certain derivative contracts was revised. This resulted in operating revenues for certain contracts, including those in discontinued operations, to be presented gross in 2003 that were on a net basis in 2002. See Note 1 for further details.

International Energy

In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. An after tax net gain of $11 million on these sales was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations. An income tax benefit of approximately $101 million was also recorded in 2003, primarily associated with the $194 million goodwill impairment recognized in 2002 for the gas marketing business in Europe, the 2003 sale of that business and certain other exit costs. This tax benefit was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $68 million as of December 31, 2004 and $63 million as of December 31, 2003. This receivable is included in Receivables in the Consolidated Balance Sheets as of December 31, 2003 and 2004. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance for the note based on management’s assessment of the probability of not collecting the entire note. The after tax loss was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

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

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

In April 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion (including $840 million debt retired by the buyer). This resulted in recording an additional $40 million after-tax gain in the second quarter of 2004. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the Asia-Pacific Business. In September 2004, International Energy repaid approximately $50 million of remaining Asia-Pacific debt from assets that were held in a fully-funded consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business. The Asia-Pacific debt had been classified as Current and Non-Current Liabilities Associated with Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2003. All after tax gains related to this transaction and the results of operations for these assets are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

In 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $78 million. The sale resulted in a reduction to Duke Energy’s consolidated indebtedness of $259 million. International Energy recorded an immaterial after tax loss on the sale, which was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. Crescent has several projects with distinguishable operations and cash flows which will be eliminated upon their sale. In the case Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the project as “discontinued operations” as required by SFAS No. 144.

In 2004, Crescent sold one apartment complex, two residential and two commercial properties resulting in sales proceeds of approximately $52 million. The $5 million after tax gain on these sales was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

In 2003, Crescent sold three retail centers and one apartment complex, all located in Florida, for a total sales price of approximately $77 million. The $11 million after tax gain on these sales was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

Other

During 2003, Duke Energy decided to exit the merchant finance business conducted by DCP. As a result, Duke Energy recorded an approximately $17 million after tax loss, which represents the excess of the carrying value of the notes receivable over the fair value, less costs to sell. Fair value of the notes receivable was estimated based primarily on discounted cash flow analysis. The after tax loss was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

During 2004, Duke Energy received approximately $58 million from the sale or collection of all of DCP’s notes receivable. An immaterial after tax gain related to these transactions was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

During 2003, Duke Energy sold Duke Energy Hydrocarbons LLC for approximately $83 million. Duke Energy recorded an approximate $14 million after tax loss on the sale, which was included in Discontinued Operations—Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.

Assets Held for Sale. The following are significant items classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2004:

• Some gathering, processing, compression and transportation assets owned by Field Services ^a

• DENA’s Bayside facility^b

• International Energy’s European Business

The following are significant items classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2003:

• Some turbines and related equipment owned by DENA

• International Energy’s European Business

• International Energy’s Asia-Pacific Business^a

• DCP’s merchant finance business^a

a Operating results for these businesses are classified as Discontinued Operations in the Consolidated Statements of Operations

b Bayside was consolidated as a result of the adoption of FIN 46 on March 31, 2004. As a result, Bayside’s operating results for the period April 1 to December 31, 2004 are included in Discontinued Operations in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations.

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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 December 31, 2004 and 2003.

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

	December 31, 2004		December 31, 2003
	(in millions)
Current assets	$	40	$	361
Investments and other assets		12		379
Property, plant and equipment, net		72		1,065
Total assets held for sale	$	124	$	1,805
Current liabilities	$	30	$	651
Long-term debt		14		514
Deferred credits and other liabilities		—		223
Total liabilities associated with assets held for sale	$	44	$	1,388

14. Property, Plant and Equipment

	December 31,
	2004			2003
	(in millions)
Land(a)	$	489		$	503
Plant
Electric generation, distribution and transmission(a)		23,937			23,577
Natural gas transmission and distribution		11,402			10,848
Gathering and processing facilities(a)		6,343			6,127
Other buildings and improvements(a)		440			448
Nuclear fuel		821			863
Equipment		1,150			1,162
Vehicles		136			135
Construction in process		715			1,007
Other(a)		1,373			1,317
Total property, plant and equipment		46,806			45,987
Total accumulated depreciation(b), (c)		(13,300	)		(12,139	)
Total net property, plant and equipment	$	33,506		$	33,848

(a) Includes capitalized leases: $87 million for 2004 and $136 million for 2003.

(b) Includes accumulated amortization of nuclear fuel: $550 million for 2004 and $604 million for 2003.

(c) Includes accumulated amortization of capitalized leases: $33 million for 2004 and $42 million for 2003.

Capitalized interest of $43 million for 2004, $132 million for 2003 and $250 million for 2002 is included in the Consolidated Statements of Operations.

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15. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate		Year Due	December 31,
				2004			2003
	(in millions)
Unsecured debt	6.5	%	2005 – 2032	$	15,516		$	16,562
Secured debt	4.5	%	2005 – 2019		1,246			2,344
First and refunding mortgage bonds	4.6	%	2008 – 2027		1,215			1,215
Trust preferred securities(a)	7.5	%	2029 – 2039		—			876
Capital leases	11.6	%	2005 – 2032		195			210
Other debt(b)	4.2	%	2005 – 2017		381			466
Commercial paper(c)	2.5	%			218			240
Preferred stock with sinking fund requirements(d)	6.8	%	2004 – 2015		—			25
Fair value hedge carrying value adjustment			2005 – 2032		80			95
Unamortized debt discount and premium, net					(19	)		(81	)
Total debt(e), (f)					18,832			21,952
Current maturities of long-term debt					(1,832	)		(1,200	)
Short-term notes payable and commercial paper(g)					(68	)		(130	)
Total long-term debt				$	16,932		$	20,622

(a) Upon the implementation of SFAS No. 150, effective July 1, 2003, the trust preferred securities were reclassified to Long-term Debt from Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Energy Corporation or Subsidiaries. Additionally, upon the adoption of the provisions of FIN 46R as of December 31, 2003, Duke Energy’s remaining trust subsidiaries that had issued the trust preferred securities were deconsolidated since Duke Energy was not the primary beneficiary of the trust subsidiaries. This resulted in Duke Energy reflecting debt to affiliates in the December 31, 2003 Long-term Debt balance. During 2004, these trust preferred securities were redeemed for approximately $850 million.

(b) Includes $172 million of Duke Energy pollution control bonds as of December 31, 2004 and 2003. As of December 31, 2004 and 2003, $40 million was secured by first and refunding mortgage bonds and $77 million was secured by a letter of credit which in turn is secured by first and refunding mortgage bond.

(c) Includes $150 million as of December 31, 2004 and 2003 that was classified as Long-term Debt on the Consolidated Balance Sheets. The weighted-average days to maturity were 8 days as of December 31, 2004 and 18 days as of December 31, 2003.

(d) Upon the implementation of SFAS No. 150, effective July 1, 2003, the preferred stock with sinking fund requirements was reclassified to Long-term Debt from Preferred and Preference Stock with Sinking Fund Requirements. As of December 31, 2003, there were 250,000 issued and outstanding shares of 6.75% Preferred Stock, Series X issued in 1993.

(e) As of December 31, 2004, $485 million of debt was denominated in Brazilian Reals with the principal indexed annually to Brazilian inflation and $3,720 million of debt was denominated in Canadian dollars. As of December 31, 2003, $437 million of debt was denominated in Brazilian Reals with the principal indexed annually to Brazilian inflation and $3,673 million of debt was denominated in Canadian dollars.

(f) Balance at December 31, 2003 excludes approximately $890 million of long-term debt, notes payable and commercial paper denominated in Australian Dollars related to International Energy’s Asia-Pacific Business. As of December 31, 2003, International Energy’s Asia-Pacific Business was classified as discontinued operations, and the debt associated with the Asia-Pacific Business was reclassified to Current and Non-Current Liabilities Associated with Assets Held for Sale. During 2004, the debt was retired as part of the sale of the Asia-Pacific Business.

(g) Weighted-average rates on outstanding short-term notes payable and commercial paper was 2.5% as of December 31, 2004 and 1.7% as of December 31, 2003.

Unsecured Debt. In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying its 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009, and $288 million of

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5.5% senior unsecured notes due in 2014. In accordance with EITF Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8.25% Equity Units in May of 2004.

Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8% Equity Units in November 2004.

During 2004, Duke Capital purchased $202 million of its outstanding notes in the open market. These purchases included $140 million of Duke Capital 5.50% senior notes due March 1, 2014, $52 million of Duke Capital 4.37% senior notes due March 1, 2009 and $10 million of Duke Capital 6.75% senior noted due February 15, 2032. These securities were purchased at the then-current market price plus accrued interest.

In May 2004, Duke Energy redeemed its Series C 6.60% senior notes due in 2038, at a $200 million face value. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued interest to the redemption date.

Convertible Debt. As of December 31, 2004, unsecured debt included $770 million of 1.75% convertible senior notes due in 2023. These senior notes, which were issued in May 2003, are convertible to Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. Upon conversion, the senior notes are potentially convertible into approximately 32.6 million shares of common stock. The conversion of these senior notes into shares of Duke Energy common stock is contingent on the occurrence of certain events during specified periods. These events include whether the price of Duke Energy common stock reaches specified thresholds, the credit rating of Duke Energy falls below certain thresholds, the convertible notes are called for redemption by Duke Energy, or specified transactions have occurred. The conditions that permit such conversion were not satisfied as of December 31, 2004. However, as a result of adopting the final consensus on EITF Issue No. 04-8, Duke Energy was required to include 32.6 million potential common shares related to Duke Energy’s $770 million contingently convertible debt issuance as outstanding in the diluted EPS calculation at December 31, 2004. (See Note 19). Holders of the senior notes may require Duke Energy to purchase all or a portion of their senior notes for cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Duke Energy may redeem for cash all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date.

In May 2004, Duke Energy issued 22,449,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in March 2001. Under the terms of the contract, the Equity Unit holders were required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement with a floor and a ceiling. The rate was 0.6414 shares of stock per Equity Unit. Duke Energy received $875 million in proceeds as a result of the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

In November 2004, Duke Energy issued 18,693,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in November 2001. Under the terms of the contract, the Equity Unit holders were required to purchase stock at the time of settlement rate based on the current market price of Duke Energy’s common stock at the time of the settlement with a floor and a ceiling. The rate was .6231 shares of stock per Equity Unit. Duke Energy received $750 million in proceeds as a result of the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

Secured Debt. Accounts Receivable Securitization. During 2003, Duke Energy completed a securitization of certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a newly formed, bankruptcy remote, special purpose subsidiary. DERF is a wholly owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy. As a result of the securitization, Duke Energy sold, and will continue to sell on a daily basis to DERF, certain accounts receivable arising from the sale of electricity and/or related services as part of Duke Energy’s franchised electric business. The proceeds from the initial sale of the accounts receivable to DERF were used for general corporate purposes in its franchised electric business, which included the repayment of outstanding commercial paper. In order to fund its purchases of accounts receivable, DERF entered into a two-year $300 million secured credit facility, with a commercial paper conduit administered by Citicorp North America, Inc. The credit facility has been subsequently amended to terminate in September 2006. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF as well

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as a covenant requiring that the ratio of Duke Energy consolidated indebtedness to Duke Energy consolidated capitalization not exceed 65%. As of December 31, 2004, the interest rate associated with the credit facility, which is based on commercial paper rates, was 2.7% and $300 million was outstanding under the credit facility. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and accordingly is reflected as a secured borrowing in the Consolidated Financial Statements. As of December 31, 2004, the $300 million outstanding balance of the credit facility was secured by approximately $447 million of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy.

Other Assets Pledged as Collateral. As of December 31, 2004, secured debt also consisted of various project financings, including Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and certain projects at Crescent. A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral. Additionally, as of December 31, 2004, substantially all of Franchised Electric’s electric plant in service was subject to a mortgage lien securing the first and refunding mortgage bonds.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $1.5 billion of floating-rate debt as of December 31, 2004, and $2.7 billion as of December 31, 2003. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2004, the average interest rate associated with floating-rate debt was 2.6%.

In October 2004, Duke Energy prepaid a portion of a $994 million floating rate facility at DENA. The payment consisted of $565 million of principal, an associated $35 million working capital facility and accrued interest on the facilities. Additionally, in December 2004, Duke Energy repaid the remaining outstanding balance of $429 million.

Related Party Debt. Other debt included $17 million related to a loan with D/FD as of December 31, 2004, and $78 million as of December 31, 2003. As part of the D/FD partnership agreement, excess cash has been loaned, without stated repayment terms, at current market rates to Duke Energy and Fluor Enterprises, Inc. The weighted-average rate of this loan was 1.98% as of December 31, 2004 and 1.52% as of December 31, 2003. During 2003, Duke Energy and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners have adopted a plan for an orderly wind-down of the business by December 2005. The entire outstanding balance of the loan with D/FD has been classified as Current Maturities of Long-term Debt on the December 31, 2004 and 2003 Consolidated Balance Sheets.

Upon the adoption of the provisions of FIN 46R as of December 31, 2003, as discussed in Note 1, Duke Energy’s remaining trust subsidiaries that had issued the trust preferred securities were deconsolidated since Duke Energy was not the primary beneficiary of the trust subsidiaries. The deconsolidation of the remaining trust subsidiaries resulted in Duke Energy reflecting debt to affiliates of $876 million to the trust subsidiaries in Long-term Debt on the December 31, 2003 Consolidated Balance Sheet. As of December 31, 2003, the debt to affiliates consisted of the following issuances: $360 million of 7.20% notes due in 2037, $258 million of 7.20% notes due in 2039 and $258 million of 8.375% notes due in 2029. During 2004, all of the issuances were redeemed for approximately $850 million. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued and unpaid distributions to the redemption date.

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2004

	(in millions)
2005	$	1,832
2006		1,991
2007		740
2008		1,202
2009		1,197
Thereafter		11,802
Total long-term debt(a)	$	18,764

(a) Excludes short-term notes payable and commercial paper of $68 million.

Annual maturities after 2009 include $450 million of long-term debt with call options, which provide Duke Energy with the option to potentially repay the debt early. Based on the years in which Duke Energy may first exercise its redemption options, it could potentially repay $100 million in 2005, $250 million in 2006, and $100 million in 2007.

Duke Energy may be required to repay certain debt should its credit ratings fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investor Service (Moody’s). As of December 31, 2004, Duke Energy had $17 million of senior unsecured

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notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $28 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of March 1, 2004, Duke Energy’s senior unsecured credit rating was BBB at S&P and Baa1 at Moody’s.

Available Credit Facilities and Restrictive Debt Covenants. As of December 31, 2004, credit facilities capacity was reduced by approximately $560 million compared to December 31, 2003, primarily related to the divested Asia-Pacific Business as discussed in Note 13. In addition, Duke Energy and DEFS renewed and replaced their credit facilities at lower amounts due to the reduced need for credit capacity. In October 2004, Duke Capital added two new credit facilities, including a $120 million bilateral credit facility with an expiration date of July 15, 2009 and a $130 million bilateral credit facility with an expiration date of October 18, 2007. Duke Capital intends to use both of these facilities for issuing letters of credit to support the business activities of its subsidiaries. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2004, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

Credit Facilities Summary as of December 31, 2004

		Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Energy
$500 three-year syndicated(a), (b)	June 2007
$150 two-year bilateral(a), (b)	September 2005
Total Duke Energy		$	650	$	150	$	—	$	150
Duke Capital LLC
$600 364-day syndicated(a), (b), (c)	June 2005
$600 three-year syndicated(a), (b), (c)	June 2007
$130 three-year bi-lateral(b), (c)	October 2007
$120 multi-year bi-lateral(b), (c)	July 2009
Total Duke Capital LLC			1,450		—		732		732
Westcoast Energy Inc.
$166 three-year syndicated(b), (e)	June 2007
$83 two-year syndicated(b), (d)	July 2005
Total Westcoast Energy Inc.			249		—		—		—
Union Gas Limited
$249 364-day syndicated(f), (g)	June 2005		249		68		—		68
Duke Energy Field Services, LLC
$250 364-day syndicated(c), (h), (i), (j)	May 2005		250		—		—		—
Total(k)		$	2,848	$	218	$	732	$	950

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

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

(c) Credit facility contains an interest coverage covenant.

(d) Credit facility is denominated in Canadian dollars, and was 100 million Canadian dollars as of December 31, 2004.

(e) Credit facility is denominated in Canadian dollars, and was 200 million Canadian dollars as of December 31, 2004.

(f) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars, and was 300 million Canadian dollars as of December 31, 2004.

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

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

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

(j) In December 2004, the credit facility expiration date was extended from March 2005 to May 2005.

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

Preferred and Preference Stock of Duke Energy’s Subsidiaries. In June 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.

In October 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 9. The Series 9 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of 125 million Canadian dollars.

Duke Energy has approximately $1,300 million of credit facilities which expire in 2005. It is Duke Energy’s intent to resyndicate the $1,300 million of expiring credit facilities.

Other Loans. During 2004 and 2003, Duke Energy had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. The amounts outstanding were $508 million as of December 31, 2004 and $467 million as of December 31, 2003. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.

16. Preferred and Preference Stock at Duke Energy

Authorized Shares of Duke Energy Preferred and Preference Stock as of December 31, 2004 and 2003

	Par Value		Shares
			(in millions)
Preferred Stock	$	100	12.5
Preferred Stock A	$	25	10.0
Preference Stock	$	100	1.5

As of December 31, 2004 and 2003, there were no shares of preference stock outstanding at Duke Energy.

Preferred Stock without Sinking Fund Requirements. The following table details Preferred Stock without Sinking Fund Requirements, which are not mandatorily redeemable financial instruments under the provisions of SFAS No. 150, as of the December 31, 2004 and 2003 Consolidated Balance Sheets.

Preferred Stock without Sinking Fund Requirements

Rate/Series	Year Issued	Shares Issued and Outstanding at December 31, 2004	December 31,
			2004		2003
			(dollars in millions)
4.50% C	1964	175,000	$	18	$	18
7.85% S	1992	300,000		30		30
7.00% W	1993	249,989		25		25
7.04% Y	1993	299,995		30		30
6.375% (Preferred Stock A)	1993	1,257,185		31		31
Total			$	134	$	134

Duke Energy has the option, but not the obligation to redeem the Preferred Stock without Sinking Fund Requirements at prices above par, but not to exceed 104% of par value, plus accumulated dividends to the redemption date. Additionally, the holders of the Preferred Stock without Sinking Fund Requirements are entitled to redeem their preferred shares at par value in the event of an involuntary liquidation or dissolution of Duke Energy, or at 105% of par value in the event of a voluntary liquidation or dissolution of Duke Energy. Therefore, in accordance with SEC rules, the Preferred Stock without Sinking Fund Requirements is classified in mezzanine equity as Preferred and Preference Stock without Sinking Fund Requirements.

Preferred and Preference Stock of Duke Energy’s Subsidiaries. In connection with the Westcoast acquisition in 2002, Duke Energy assumed approximately $411 million of authorized and issued redeemable preferred and preference

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shares at Westcoast and Union Gas. As of December 31, 2004 and 2003, these preferred and preference shares at Westcoast and Union Gas totaled $225 and $401 million, respectively. Since these preferred and preference shares are redeemable at the option of holder, as well as Westcoast and Union Gas, these preferred and preference shares do not meet the definition of a mandatorily redeemable instrument under SFAS No. 150. As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.

17. Commitments and Contingencies

General Insurance

Duke Energy carries, through its captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Duke Energy’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) financial services insurance policies in support of the indemnification provisions of the company’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Bison is a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provides property and business interruption reinsurance coverage respectively for Duke Energy’s non-nuclear facilities, and accounts for its membership under the cost method, as Duke Energy does not have the ability to exert significant influence. Should Bison terminate its membership in either OIL, sEnergy or both, it could be liable for additional premium assessments. Bison continues to be a member of OIL and sEnergy in 2005 and purchases coverages provided by both companies.

Duke Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of Duke Energy’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Nuclear Insurance

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to insure against public liability claims resulting from nuclear incidents to the full limit of liability, approximately $10.8 billion.

Primary Liability Insurance. Duke Energy has purchased the maximum available private primary liability insurance as required by law. As of January 1, 2003, the maximum amount of available private primary insurance increased from $200 million to $300 million and Duke Energy increased coverages on both nuclear liability and certain worker tort claim insurance to $300 million.

Excess Liability Insurance. This policy currently provides approximately $10.5 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary insurance program of risk pooling. The $10.5 billion is the sum of the current potential cumulative retrospective premium assessments of $101 million per licensed commercial nuclear reactor. This would be increased by $101 million for each additional commercial nuclear reactor licensed, or reduced by $101 million for nuclear reactors no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the U.S. If such an incident should occur and public liability damages exceed primary insurances, licensees may be assessed up to $101 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $101 million is subject to indexing for inflation and may be subject to state premium taxes.

Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and business interruption insurance coverage for Duke Energy’s nuclear facilities under three policy programs:

Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy’s nuclear facilities.

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Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance: $2.25 billion for the Catawba Nuclear Station and $2.0 billion each for the Oconee and McGuire Nuclear Stations.

Business Interruption Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each McGuire and Catawba unit is insured for up to $3.5 million per week, and the Oconee units are insured for up to $2.8 million per week. Coverage amounts decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period and continues at 100% for 52 weeks and 80% for the next 110 weeks.

If NEIL’s losses exceed its reserves for any of the above three programs, Duke Energy is liable for assessments of up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$35 million, Excess Property Insurance—$44 million and Business Interruption Insurance—$29 million.

The other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act’s excess secondary insurance program of risk pooling, or the NEIL policies.

Environmental

Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. Like others in the energy industry, Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve ground water remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary, as a function of 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 consolidated results of operations, cash flows or financial position.

Clean Water Act. The Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes best technology available (BTA) requirements for existing steam electric generating facilities’ cooling water intake structures to protect fish and other aquatic organisms. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina and its three natural gas-fired generating facilities in California are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to generate information for use in determining necessary facility-specific BTA requirements and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures for a facility are determined and approved by regulators, each facility will typically have five or more years to implement the measures. Due to the wide range of BTA 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.

Air Quality Control. In 1998, the EPA issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans (SIPs) to significantly reduce emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various states, industry and other interests, including Duke Energy and the states of North Carolina and South Carolina. In 2000, the court upheld most aspects of the EPA rule. The same court subsequently extended the compliance deadline for emission reductions to May 31, 2004. Both North Carolina and South Carolina have revised their SIPs in response to the EPA’s 1998 rule, and the EPA has approved those revisions. Duke Energy has completed all necessary actions to meet the EPA rule and requirements, incurring approximately $653 million in capital costs for emission controls.

North Carolina Clean Air Legislation. As discussed in Note 4, in 2002, the state of North Carolina passed clean air legislation in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide and nitrogen oxides from coal-fired power plants in the state over the next ten years.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were accruals related to extended environmental-related activities of $83 million as of December 31, 2004 and $94 million as of December 31, 2003. The accrual for extended environmental-related activities represents Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

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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 NSR provisions 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’s NSR requirements when it undertook those projects without obtaining permits and installing emission controls for sulfur dioxide, nitrogen oxide 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. Moreover, the EPA’s allegations run counter to previous EPA guidance regarding the applicability of the NSR permitting requirements. In 2003, the trial court issued an opinion in response to the parties’ motions for summary judgment which effectively adopted Duke Energy’s position regarding the legal tests for determining what is “routine” and for calculation of emissions. Based upon a joint motion of the parties in the case, the court in April 2004 entered an Order and Final Judgment finding in favor of Duke Energy. The joint motion notified the court that the government could not prove its allegations at trial against Duke Energy in light of the legal standards established by the court in its 2003 order. The judgment reflects that Duke Energy did not violate the NSR program under the CAA. The government appealed the judgment to the U.S. Fourth Circuit Court of Appeals in June 2004. The Fourth Circuit heard oral argument on February 3, 2005. A decision is pending. Based on the current rulings by the trial court, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position. Subsequent rulings by the appellate court could significantly affect the outcome.

Western Energy Litigation. Since 2000, plaintiffs have filed 45 lawsuits in four western states against Duke Energy affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Ten suits have been dismissed on filed rate and federal preemption grounds. The U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these ten lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit has petitioned the U.S. Supreme Court for certiorari and that court has invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted. The plaintiffs in two of the ten dismissed actions to date have not filed appeals.

• In July 2004, Duke Energy reached an agreement in principle resolving the class-action litigation (the Western Power Class Action) involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement (the California Settlement) is part of a more comprehensive settlement involving FERC refunds and other proceedings. The class-action provisions of the California Settlement are subject to court approval. The California Settlement is addressed in more detail in the “Western Energy Regulatory Matters and Investigations” section below.

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

Separately, in 2003, Pacific Gas and Electric Company (PG&E) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of a bilateral power contract between the parties in early 2001. PG&E sought in excess of $25 million from DETM pursuant to a disputed “true-up” agreement between the parties. The PG&E true-up dispute was resolved in connection with the California Settlement.

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

Western Energy Regulatory Matters and Investigations. Duke has been the subject, along with other energy suppliers and producers, of several investigations and regulatory proceedings at the state and federal levels that are looking into the

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causes of high wholesale electricity prices in the western United States during 2000 and 2001. Duke Energy has resolved these issues, which are described in detail below, through the California Settlement.

• In FERC refund proceedings, the FERC ordered some sellers, including DETM, to refund, or to offset against outstanding accounts receivable, amounts billed for electricity sales in excess of a FERC-established proxy price. In 2002, the presiding administrative law judge in the FERC refund proceedings issued preliminary estimates that indicated DETM had refund liability of approximately $95 million. The FERC issued staff recommendations and an order in 2003 that modified the prior refund methodology by changing the gas proxy price used in the refund calculation. Platts, an energy industry publication, reported that a FERC spokesman announced that the methodology change could increase the total aggregate refund amount for all generators from $1.8 billion to at least $3.3 billion.

• In 2003, the FERC issued an Order to Show Cause concerning “Enron-type gaming behavior,” and a companion order requiring suppliers, including DETM, to justify bids in the California Independent System Operator and the California Power Exchange markets made above the level of $250 per megawatt hour from May 1, 2000 through October 1, 2000. Later in 2003, the FERC Staff and Duke Energy announced two agreements to resolve all matters at issue in both of those orders. Duke Energy agreed to pay up to $4.59 million to benefit California and western electricity consumers, pending final approval by the FERC. The FERC approved the agreement involving bidding practices and rejected objections to the agreement. The objectors sought review of the FERC’s ruling on this agreement from the U.S. Ninth Circuit Court of Appeals. In April 2004, the administrative law judge reviewing the remaining agreement approved the settlement and rejected the objections. FERC approved the second agreement and made findings that set Duke Energy’s settlement amount with respect to both agreements at approximately $3 million, payment of which has been credited towards the California Settlement payment amount. The challenges to the two agreements are resolved through the California Settlement.

• At the state level, the California Public Utilities Commission (CPUC), a California State Senate Select Committee, the California Attorney General (with participation by the Attorneys General of Washington and Oregon) and the San Diego District Attorney have conducted formal and informal investigations involving Duke Energy regarding the California energy markets, including review of alleged manipulation of energy prices. In addition, the U.S. Attorney’s Office in San Francisco served a grand jury subpoena on Duke Energy in 2002 seeking information relating to possible manipulation of the California electricity markets, including potential antitrust violations. All investigations (the State Civil Investigations), other than criminal investigations are resolved through the California Settlement. Duke Energy does not believe the outcome of any remaining criminal investigation will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In July 2004, Duke Energy reached an agreement in principle with the FERC, the State of California and other in- and out-of-state participants to settle the FERC refund proceedings and other significant litigation related to the western energy markets during 2000-2001 described above. The class action portion of the settlement is subject to court approval, but FERC approved all remaining provisions of the settlement in December 2004. As part of the agreement, Duke Energy agreed to provide approximately $208 million in cash and credits to various parties involved in the settlement. The parties agreed to forgo all claims relating to refunds or other monetary damages for sales of electricity during the settlement period (January 1, 2000 through June 20, 2001), and claims alleging Duke Energy received unjust or unreasonable rates for the sale of electricity during the settlement period. The settlement resolved, among other matters:

• All western refund proceedings pending before the FERC

• The State Civil Investigations

• The Western Power Class Action

• Natural gas price issues raised by the California attorney general, PG&E, SCE and San Diego Gas & Electric Company

Duke Energy recorded an approximate $105 million pre-tax charge in the second quarter of 2004 at DENA to reflect the settlement agreement. This charge was recorded in Discontinued Operations on the Consolidated Statements of Operations. In December 2004, Duke Energy tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. This remaining amount, which is fully reserved, will be paid upon court approval of the class-action settlement.

In Lockyer v. FERC, the U.S. Ninth Circuit Court of Appeals ruled in September 2004 that while FERC’s authorization of market based rate tariffs complied with the Federal Power Act, the failure by sellers of electricity to file appropriate quarterly reports provides the FERC with authority to award refunds relating to the period prior to October 2000. The court declined to order refunds requested by the State of California but remanded the case to the FERC for further proceedings consistent with its opinion. The California Settlement resolves refund issues relating to the post-October 2000 refund period as well as the pre-October 2000 period that was at issue in the Lockyer case. While the Lockyer ruling does not affect Duke Energy’s settlement, the decision could give rise to potential refund liability at the FERC for market-based rate sellers generally, including Duke Energy affiliates, to the extent quarterly reports filed by those entities are incomplete or inaccurate.

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Trading Related Litigation. Beginning in 2002, 17 shareholder class-action lawsuits were filed against Duke Energy: 13 in the U.S. District Court for the Southern District of New York and four in the U.S. District Court for the Western District of North Carolina. These lawsuits arose out of allegations that Duke Energy improperly engaged in “round trip” trades which resulted in an alleged overstatement of revenues over a three-year period. By late 2003, the two federal courts had dismissed all 17 lawsuits. Plaintiffs in the New York cases appealed the dismissal order to the U.S. Second Circuit Court of Appeals. On November 15, 2004, appellate court affirmed the trial court’s dismissal of the New York cases.

By letter dated April 16, 2004, Duke Energy received notice that a shareholder reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same issues raised in the dismissed shareholder lawsuits, the notice stated that the shareholder intended to initiate derivative shareholder litigation within 90 days from the date of the letter if Duke Energy did not initiate litigation within the stated timeframe. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims. By letter dated January 21, 2005, another shareholder reactivated a 2002 litigation demand. The reactivated demand arises out of the same issues that were raised in the April 16 reactivated demand as well as matters that were the subject of the California Settlement. The special committee is reviewing this second demand.

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 NYMEX during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The cases claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants. On January 25, 2005, the plaintiffs filed a motion for class certification; defendants are opposing the motion which has not yet been scheduled for hearing. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

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

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

In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Energy recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the 3 indicted former DETMI employees pled guilty to a books and records violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls.

In February 2004, Duke Energy received a request for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activity of a former DETM trader. Duke Energy has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome at this time.

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

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

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

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

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible, provides for coverage to Duke Energy up to an aggregate of $1.6 billion. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within noncurrent assets. Amounts recognized as reserves in the Consolidated Balance Sheets are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

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Duke Energy has exposure to certain legal matters that are described herein. As of December 31, 2004, Duke Energy has recorded reserves of approximately $1.4 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of December 31, 2004, 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

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. 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. Duke Energy would record a reserve if events occurred that required that one be established. (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.

Operating and Capital Lease Commitments

Duke Energy leases assets in several areas of its operations. Consolidated rental expense for operating leases was $124 million in 2004, $133 million in 2003 and $133 million in 2002, and included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Amortization of assets recorded under capital leases was included in Depreciation and Amortization or in Discontinued Operations on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases, which at inception had a noncancelable term of more than one year, and capital leases as of December 31, 2004:

	Operating Leases		Capital Leases
	(in millions)
2005	$	94	$	119
2006		78		14
2007		59		14
2008		49		15
2009		43		15
Thereafter		207		18
Total future minimum lease payments	$	530	$	195

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 enters into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Mixed Oxide (MOX) Guarantees. DCS is the prime contractor to the DOE under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of December 31, 2004, Duke Energy, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

The Prime Contract consists of a “Base Contract” phase and successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching

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agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2004, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and the first option phase covering mission reactor modifications.

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

In connection with the Prime Contract, Duke Energy, through its Duke Power franchised electric business, has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2004, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.

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

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

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

Duke Energy has not recorded on its Consolidated Balance Sheets any liability for the potential exposure under the Duke Power Guarantee per FIN 45, because DPSG and Duke Power are under common control.

Other Guarantees and Indemnifications. Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of December 31, 2004 was approximately $1.1 billion. Of this amount, approximately $660 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $60 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2008 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method projects, 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 an unconsolidated 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 December 31, 2004 was approximately $60 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

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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 December 31, 2004 was approximately $400 million. Of this amount, approximately $350 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities. Substantially all of these letters of credit expire in 2005.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of December 31, 2004, Duke Capital had guaranteed approximately $80 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2005 and 2006. Of this amount, approximately $10 million relates to obligations of less than wholly owned consolidated entities.

Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of December 31, 2004, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, with approximately $8 million expiring in 2009 and the remainder having no contractual expiration. International Energy was the guarantor of approximately $70 million of performance guarantees associated with less than wholly-owned entities, with substantially all of the guarantees expiring in 2005.

Duke Energy has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Energy but which have been sold to third parties, such as DukeSolutions and DE&S. These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to goods and services provided. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Energy related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Energy related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of Duke Solutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2004 to 2019, with others having no specific term. Duke Energy is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

Additionally, 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 such bank to Georgia Power Company, which expires in 2005, related to the obligation of a KGen subsidiary under a seven year power sales agreement, commencing in May 2005, as discussed in Note 2. 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 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 made by Duke Energy with respect to the $120 million letter of credit.

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

As of December 31, 2004, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

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19. Earnings Per Share (EPS)

Basic earnings per share are computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share are computed by dividing earnings available for common stockholders by the diluted weighted-average number of common shares outstanding each period. Diluted earnings per share 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 or converted into common stock.

The following tables illustrate 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 2004, 2003 and 2002.

(in millions, except per share data)	Income (Loss)			Average Shares	EPS
2004
Income from continuing operations	$	1,252
Less: Dividends and premiums on redemption of preferred and preference stock		(9	)
Income from continuing operations—basic	$	1,243		931	$	1.33
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		8		33
Income from continuing operations—diluted	$	1,251		966	$	1.29
2003
Income from continuing operations	$	71
Less: Dividends and premiums on redemption of preferred and preference stock		(15	)
Income from continuing operations—basic	$	56		903	$	0.06
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock		—		1
Income from continuing operations—diluted	$	56		904	$	0.06
2002
Income from continuing operations	$	1,145
Less: Dividends and premiums on redemption of preferred and preference stock		(13	)
Income from continuing operations—basic	$	1,132		836	$	1.35
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock		—		2
Income from continuing operations—diluted	$	1,132		838	$	1.35

The increase in weighted-average shares outstanding at December 31, 2004 compared to December 31, 2003 was due primarily to the issuance of 41.1 million shares associated with the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004. The increase in diluted weighted-average shares outstanding at December 31, 2004 compared to December 31, 2003 was primarily due to Duke Energy adopting the final consensus on EITF Issue No. 04-8 which required the inclusion of 32.6 million potential common shares related to Duke Energy’s $770 million contingently convertible debt issuance. (See Note 15.) The effect of the contingently convertible debt was anti-dilutive as of December 31, 2003, and as such 21.9 million of potential common shares were not included in “Effect of dilutive securities” for that period.

Options, restricted stock, performance and phantom stock awards to purchase approximately 23.2 million shares as of December 31, 2004, 25.2 million shares as of December 31, 2003 and 31.4 million shares as of December 31, 2002 were not included in “Effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

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20. Stock-Based Compensation

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.

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 Corporation 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.

Stock Option Activity

	Options (in thousands)		Weighted- Average Exercise Price
Outstanding at December 31, 2001	26,406		$	33
Granted(a)	9,406			34
Exercised	(1,452	)		23
Forfeited	(3,151	)		37
Outstanding at December 31, 2002	31,209			34
Granted	8,248			15
Exercised	(339	)		11
Forfeited	(6,702	)		34
Outstanding at December 31, 2003	32,416			29
Exercised	(867	)		15
Forfeited	(2,993	)		33
Outstanding at December 31, 2004	28,556			29

(a) Includes 2,746 converted Westcoast stock options

Stock Options at December 31, 2004

	Outstanding				Exercisable
Range of Exercise Prices	Number (in thousands)	Weighted- Average Remaining Life (in years)	Weighted- Average Exercise Price		Number (in thousands)	Weighted- Average Exercise Price
$9 to $14	5,025	7.8	$	14	1,179	$	13
$15 to $20	1,979	8.1		17	742		18
$21 to $24	397	4.0		22	397		22
$25 to $28	5,945	4.6		26	5,894		26
$29 to $33	4,084	3.8		30	4,027		30
$34 to $37	805	7.1		34	484		34
$38 to $39	6,036	7.0		38	4,901		38
> $39	4,285	6.0		43	4,171		43
Total	28,556	6.1			21,795		32

On December 31, 2003, Duke Energy had 20.4 million exercisable options with a $32 weighted-average exercise price. On December 31, 2002, Duke Energy had 19.1 million exercisable options with a $32 weighted-average exercise price.

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The weighted-average fair value per option granted was $4 for 2003 and $10 for 2002. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model. There were no options granted in 2004.

Weighted-Average Assumptions for Option-Pricing

	2003		2002
Stock dividend yield	3.5	%	3.4	%
Expected stock price volatility	37.5	%	29.9	%
Risk-free interest rates	3.6	%	5.0	%
Expected option lives	7 years		7 years

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under restricted stock awards, stock-based performance awards and phantom stock awards. Stock-based performance awards granted under the 1998 Plan vest over periods from three to seven years. Vesting can occur in three years, at the earliest if performance is met. Duke Energy awarded 1,584,840 shares (fair value of approximately $34 million at grant dates) in 2004 and 75,000 shares (fair value of approximately $2 million at grant dates) in 2003, and 16,000 shares (fair value of approximately $1 million at grant dates) in 2002. Compensation expense for the performance awards is charged to earnings over the vesting period and totaled $10 million in 2004, $3 million in 2003 and $4 million in 2002.

Phantom stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 1,283,220 shares (fair value of approximately $27 million at grant dates) in 2004, 285,000 shares (fair value of approximately $5 million at grant dates) in 2003, and 54,430 shares (fair value of approximately $2 million at grant dates) in 2002. Compensation expense for the phantom awards is charged to earnings over the vesting period and totaled $14 million in 2004, $6 million in 2003 and $10 million in 2002.

Restricted stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 169,160 shares (fair value of approximately $4 million at grant dates) in 2004, 19,897 shares (fair value of less than $1 million at grant dates) in 2003, and 14,260 shares (fair value of less than $1 million at grant dates) in 2002. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled $1 million in 2004, $1 million in 2003 and $2 million in 2002.

Duke Energy’s 1996 Stock Incentive Plan (the 1996 Plan) allowed four million shares of common stock for awards to employees. As of December 31, 2004, there are no more awards outstanding under the 1996 Plan. Duke Energy awarded no restricted shares in 2004, 2003 and 2002. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled less than $1 million in 2004 and 2003 and $1 million in 2002. The 1996 Plan is not available for new awards.

21. Employee Benefit Plan

Duke Energy U.S. Retirement Plan. Duke Energy and its subsidiaries maintain a non-contributory defined benefit retirement plan. The plan covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy made a voluntary contribution of $250 million to its defined benefit retirement plan in 2004 and $181 million in 2003. No contribution to the Duke Energy plan was made in 2002. Duke Energy does not anticipate making a contribution to the plan in 2005.

The net unrecognized transition asset, resulting from the implementation of accrual accounting, is amortized over approximately 20 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plan.

Westcoast Canadian Retirement Plans. The Westcoast benefit plans are reported separately due to actuarial assumption differences. Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings.

Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy made contributions to the Westcoast DB plans of approximately $28 million in 2004, $11 million in 2003, and $9 million in 2002. Duke Energy anticipates that it will make contributions of approximately $33 million to the Westcoast DB plans in 2005. Duke Energy also made contributions to the DC plans of $3 million in 2004, $3 million in 2003, and $2 million in 2002. Duke Energy anticipates that it will make contributions to the DC plans of approximately $3 million in 2005.

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The net unrecognized transition asset and actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the DB retirement plans is 13 years. Westcoast uses a September 30 measurement date for its plans.

Components of Net Periodic Pension Costs

	Duke Energy U.S.									Westcoast
	For the Years Ended December 31,
	2004			2003			2002			2004			2003			2002
	(in millions)
Service cost benefit earned during the year	$	64		$	70		$	69		$	8		$	7		$	6
Interest cost on projected benefit obligation		160			175			177			26			23			17
Expected return on plan assets		(233	)		(236	)		(267	)		(24	)		(24	)		(19	)
Amortization of prior service cost		(2	)		(3	)		(3	)		—			—			—
Amortization of net transition asset		(4	)		(4	)		(4	)		—			—			—
Curtailment (gain) /loss		(1	)		—			—						2			—
Amortization of loss		15			—			—			3			—			—
Special termination benefit cost		—			—			1			1			5			—
Net periodic pension (income) / cost (a)	$	(1	)	$	2		$	(27	)	$	14		$	13		$	4

As required by SFAS No. 87 “Employers’ Accounting for Pensions”, Duke Energy amortized actuarial losses in its U.S. plan of $15 million. The amortization of these losses in 2004 is primarily attributable to lower than expected asset returns over the past five years.

Reconciliation of Funded Status to Net Amount Recognized

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2004			2003			2004			2003
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	2,763		$	2,671		$	434		$	334
Service cost		64			70			8			7
Interest cost		160			175			26			23
Actuarial losses / (gains)		17			60			(8	)		27
Plan amendments		—			4			6			—
Participant contributions		—			—			2			2
Benefits paid		(298	)		(217	)		(28	)		(25	)
Curtailment		(13	)		—			—			2
Divestiture		—			—			—			(10	)
Special termination benefits		—			—			7			—
Foreign currency impact		—			—			33			74
Obligation at measurement date	$	2,693		$	2,763		$	480		$	434

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	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2004			2003			2004			2003
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	2,477		$	2,120		$	324		$	255
Actual return on plan assets		298			393			29			35
Benefits paid		(298	)		(217	)		(28	)		(25	)
Employer contributions		—			181			12			11
Plan participants’ contributions		—			—			2			2
Divestiture		—			—			—			(9	)
Foreign currency impact		—			—			23			55
Plan assets at measurement date	$	2,477		$	2,477		$	362		$	324
Funded status	$	(216	)	$	(286	)	$	(118	)	$	(110	)
Unrecognized net experience loss		740			816			68			79
Unrecognized prior service cost		(4	)		(7	)		9			—
Special termination benefits		—			—			—			(5	)
Unrecognized net transition asset		—			(4	)		—			—
Contributions made after measurement date		250			—			19			3
Net amount recognized	$	770		$	519		$	(22	)	$	(33	)

For the Duke Energy U.S. plan, the accumulated benefit obligation was $2,607 million at September 30, 2004 and $2,646 million at September 30, 2003.

For Westcoast, the accumulated benefit obligation was $435 million at September 30, 2004 and $394 million at September 30, 2003.

Amounts Recognized in the Consolidated Balance Sheets Consist of:

	Duke Energy U.S.					Westcoast
	For the Year Ended December 31,
	2004		2003			2004			2003
	(in millions)
Accrued pension liability	$	—	$	(170	)	$	(53	)	$	(70	)
Pre-funded pension costs		120		—			—			—
Deferred income tax asset		254		270			13			13
Accumulated other comprehensive income		396		419			18			21
Net amount recognized	$	770	$	519		$	(22	)	$	(36	)

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Additional Information:

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2004			2003			2004			2003
	(in millions)
Increase/(Decrease) in minimum liability included in other comprehensive income, net of tax	$	(23	)	$	(51	)	$	(3	)	$	7

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	Duke Energy U.S.				Westcoast
	For the Years Ended December 31,
	2004		2003		2004		2003
	(in millions)
Projected benefit obligation	$	2,693	$	2,763	$	479	$	432
Accumulated benefit obligation		2,607		2,646		434		393
Fair value of plan assets		2,477		2,477		361		323

Assumptions Used for Pension Benefits Accounting

	Duke Energy U.S.			Westcoast
Benefit Obligations	2004	2003	2002	2004	2003	2002
	(percentages)
Discount rate	6.00	6.00	6.75	6.25	6.00	6.50
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Net Periodic Benefit Cost
	2004	2003	2002	2004	2003	2002
Discount rate	6.00	6.75	7.25	6.00	6.50	7.25
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	8.50	8.50	9.25	7.50	7.75	8.50

For the Duke Energy U.S. plan the discount rate used to determine the pension obligation is based on the current rates earned on long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Plan Assets Duke Energy U.S.:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2004		2003
US equity securities	45	%	45	%	44	%
Non-US equity securities	20		21		20
Debt securities	32		31		35
Real estate	3		3		1
Total	100	%	100	%	100	%

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Duke Energy U.S. assets for both the pension and other post retirement benefits are maintained by a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

The long-term rate of return of 8.5% as of September 30, 2004 for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non-U.S. equities, 2.2% for fixed income securities, and 0.2% for real estate.

Plan Assets Westcoast:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2004		2003
Canadian equity securities	25	%	40	%	37	%
US equity securities	20		12		15
EAFE equity securities(a)	20		16		15
Debt securities	35		32		33
Total	100	%	100	%	100	%

(a) EAFE—Europe, Australasia, Far East

Westcoast assets for registered pension plans are maintained by a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification. Under the Income Tax Act (Canada), pension funds are only permitted to invest 30% of the book value of assets in foreign investments.

The long-term rate of return of 7.5% as of September 30, 2004 for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted average returns expected by asset classes were 2.0% for Canadian equities, 1.9% for U.S. equities, 1.9% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities.

The following benefit payments, which reflect expected future service, as appropriate, as expected to be paid over the next five years and thereafter:

Expected Benefit Payments

	U.S. Plan		Westcoast Plans
	(in millions)
Years Ended December 31,
2005	$	148	$	35
2006		159		36
2007		181		37
2008		197		38
2009		230		39
2010 – 2014		1,371		212

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy contributes to the plan a matching contribution equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay

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period. Duke Energy expensed employer matching contributions of $57 million in 2004, $63 million in 2003, and $71 million in 2002. Dividends on Duke Energy shares held by the savings plan are charged to retained earnings when declared and shares held in the plan are considered outstanding in the calculation of basic and diluted earnings per share.

Duke Energy also maintains a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. Duke Energy recognized net periodic pension expense of $11 million in 2004, $11 million in 2003, and $10 million in 2002. There are no plan assets. The projected benefit obligation was $86 million as of September 30, 2004 and $101 million as of September 30, 2003.

Westcoast also provides non-registered defined benefit supplemental pensions to all employees who retire under a defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). Westcoast recognized net periodic pension expense of $4 million in 2004, $4 million in 2003, and $3 million in 2002. There are no plan assets. The projected benefit obligation was $66 million as of September 30, 2004 and $60 million as of September 30, 2003.

Duke Energy U.S. Other Post-Retirement Benefits. Duke Energy and most of its subsidiaries provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation, resulting from accrual accounting, is amortized over approximately 20 years.

Westcoast Other Post-Retirement Benefits. Westcoast provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply for employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

Other post-retirement benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation, resulting from accrual accounting, is amortized over the average remaining service period of the active employees covered by the plans. The average remaining service period of the active employees is 18 years.

Components of Net Periodic Post-Retirement Benefit Costs

	Duke Energy U.S.									Westcoast
	For the Years Ended December 31,
	2004			2003			2002			2004			2003		2002
	(in millions)
Service cost benefit earned during the year	$	5		$	5		$	5		$	3		$	2	$	2
Interest cost on accumulated post-retirement benefit obligation		47			51			50			5			4		2
Expected return on plan assets		(19	)		(21	)		(24	)		—			—		—
Amortization of prior service cost		1			1			1			(1	)		—		—
Amortization of net transition liability		16			18			18			—			—		—
Curtailment loss		—			21			—			—			1		—
Amortization of loss		8			5			—			1			—		—
Net periodic post-retirement benefit costs	$	58		$	80		$	50		$	8		$	7	$	4

During 2003, Duke Energy experienced workforce reductions and recognized other post-retirement employee benefits curtailments of $21 million.

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Reconciliation of Funded Status to Accrued Post-Retirement Benefit Costs

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2004			2003			2004			2003
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	924		$	779		$	81		$	49
Service cost		5			5			3			2
Interest cost		47			51			5			4
Plan participants’ contributions		16			12			—			—
Actuarial (gain)/loss		(134	)		142			(5	)		30
Benefits paid		(76	)		(66	)		(3	)		(2	)
Divestiture		—			—			—			(2	)
Plan curtailments		—			1			—			1
Plan amendments		—			—			—			(12	)
Foreign currency impact		—			—			5			11
Accumulated post-retirement benefit obligation at measurement date	$	782		$	924		$	86		$	81
	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2004			2003			2004			2003
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	242		$	227		$	—		$	—
Actual return on plan assets		20			32			—			—
Benefits paid		(76	)		(66	)		(3	)		(2	)
Employer contributions		41			37			3			2
Plan participants’ contributions		16			12			—			—
Plan assets at measurement date	$	243		$	242		$	—		$	—
Funded status	$	(539	)	$	(682	)	$	(86	)	$	(81	)
Employer contributions made after measurement date		9			11			1			1
Unrecognized net experience loss		202			346			28			32
Unrecognized prior service cost		2			2			(12	)		(12	)
Unrecognized transition obligation		128			143			—			—
Accrued post-retirement benefit costs	$	(198	)	$	(180	)	$	(69	)	$	(60	)

For measurement purposes, plan assets were valued as of September 30 for both the Duke Energy U.S. and Westcoast plans.

In May 2004, the FASB staff issued FASB FSP 106-2. The Modernization Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. The FSP provides guidance on the accounting for the subsidy. Duke Energy adopted this FSP and retroactively applied this FSP as of the date of issuance for its U.S. plan. As a result of anticipated prescription drug subsidy, the accumulated post-retirement benefit obligation decreased by $96 million. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $12 million for 2004. The actuarial gain included in the change in benefit obligation of $134 million in 2004 is primarily due to the recognition of anticipated employer savings as a result of Medicare Part D. FSP 106-2 provides guidance that the effect of the federal subsidy should be recognized as an actuarial gain.

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Assumptions Used for Post-Retirement Benefits Accounting

	Duke Energy U.S.			Westcoast
Determined Benefit Obligations	2004	2003	2002	2004	2003	2002
	(percentages)
Discount rate	6.00	6.00	6.75	6.25	6.00	6.50
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
	Duke Energy U.S.			Westcoast
Determined Expense	2004	2003	2002	2004	2003	2002
Discount rate	6.00	6.75	7.25	6.00	6.50	7.25
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	8.50	8.50	9.25	—	—	—
Assumed tax ratea	39.11	39.11	39.60	—	—	—

a Applicable to the health care portion of funded post-retirement benefits

For the Duke Energy U.S. plan the discount rate used to determine the pension obligation is based on current rates earned on long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Plan Assets Duke Energy U.S.:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2004		2003
US equity securities	45	%	45	%	44	%
Non-US equity securities	20		21		20
Debt securities	32		31		35
Real estate	3		3		1
Total	100	%	100	%	100	%

Duke Energy U.S. assets for both the pension and other post retirement benefits are maintained by a Master Trust. The investment objective of the trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. US equities are held for their high expected return. Non-US equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

Duke Energy also invests other post-retirement assets in the Duke Energy Corporate Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBA’s is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed. VEBA I has a target allocation of 30% U.S. equities, 45% fixed income securities and 25% cash. VEBA II has a target allocation of 50% U.S. equities and 50% fixed income securities.

The long-term rate of return of 8.5% as of September 30, 2004 for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non U.S. equities, 2.2% for fixed income securities, and 0.2% for real estate.

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Assumed Health Care Cost Trend Rates

	Duke Energy U.S.								Westcoast
	Not Medicare Eligible				Medicare Eligible
	2004		2003		2004		2003		2004		2003
Health care cost trend rate assumed for next year	9.50	%	10.50	%	12.5	%	13.50	%	9.00	%	10.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	6.00	%	6.00	%	6.00	%	6.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2009		2009		2012		2012		2008		2008

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Duke Energy U.S. Plan (millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	3	$	(3	)
Effect on post-retirement benefit obligation		50		(40	)

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans (millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	1	$	—
Effect on post-retirement benefit obligation		11		(10	)

Duke Energy and Westcoast expect to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.

Expected Benefit Payments and Subsidies (in millions)

	U.S. Plan Payments		U.S. Plan Expected Subsidies		Westcoast Plans
	(in millions)
2005	$	58	$	—	$	4
2006		60		7		4
2007		62		8		5
2008		64		8		5
2009		66		9		5
2010 – 2014		345		47		30

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22. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
	(In millions, except per share data)
2004
Operating revenues	$	5,126	$	4,800	$	5,081	$	5,542		$	20,549
Operating income		555		811		870		725			2,961
Net income		311		432		389		358			1,490
Earnings available for common stockholders		309		429		387		356			1,481
Earnings per share
Basic	$	0.34	$	0.46	$	0.41	$	0.38		$	1.59
Diluted(a)	$	0.33	$	0.45	$	0.40	$	0.36		$	1.54
2003
Operating revenues	$	4,844	$	4,231	$	4,420	$	4,526		$	18,021
Operating income (loss)		857		621		203		(862	)		819
Income (loss) before cumulative effect of change in accounting principle		387		424		49		(2,021	)		(1,161	)
Net income (loss)		225		424		49		(2,021	)		(1,323	)
Earnings (loss) available for common stockholders		222		417		46		(2,023	)		(1,338	)
Earnings (loss) per share before cumulative effect of change in accounting principle
Basic	$	0.43	$	0.46	$	0.05	$	(2.23	)	$	(1.30	)
Diluted(b)	$	0.43	$	0.45	$	0.05	$	(2.23	)	$	(1.30	)
Earnings (loss) per share
Basic	$	0.25	$	0.46	$	0.05	$	(2.23	)	$	(1.48	)
Diluted(c)	$	0.25	$	0.45	$	0.05	$	(2.23	)	$	(1.48	)

(a) Diluted EPS for the first, second and third quarters was retrospectively adjusted for EITF 04-08. Previously reported diluted EPS was $0.34, $0.46 and $0.41, respectively.

(b) Diluted EPS (before cumulative change in accounting principle) for the second quarter was retrospectively adjusted for EITF 04-08. Previously reported diluted EPS was $0.46.

(c) Diluted EPS for the second quarter was retrospectively adjusted for EITF 04-08. Previously reported diluted EPS was $0.46.

The amounts in the above tables have been adjusted from previously reported amounts due to operations that were classified as discontinued operations (see Note 13). Also, diluted EPS (before cumulative effect of change in accounting principle) and diluted EPS have been retrospectively adjusted for EITF 04-08 (See Note 1).

During the first quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $256 million pre-tax gain on sale of International Energy’s Asia-Pacific Business (see Note 13); and an approximate $360 million pre-tax charge in 2004 associated with the sale of DENA’s Southeast Plants (see Note 2).

During the second quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $130 million (net of minority interest of $5 million) pre-tax gain related to the settlement of the Enron bankruptcy proceedings; a $39 million net increase in the pre-tax gains ($30 million increase to the after tax gains) originally recorded on the sales of International Energy’s Asia-Pacific Business (see Note 13 ) and its European Business; a $52 million release of various income tax reserves (see Note 6); and a $105 million pre-tax charge related to the California and Western U.S. energy markets settlement (see Note 17).

During the third quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $48 million tax benefit related to the realignment of certain subsidiaries of Duke Energy and the pass-through structure of these for U.S. income tax purposes ($20 million is included in continuing operation, see Note 6, the remainder is in discontinued operations); and impairments of $45 million (net of minority interest of $26 million) related to asset impairments, losses on asset sales and write-down of equity investments at Field Services (see note 12).

During the fourth quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $180 million of pre-tax gains associated with the sales of two DENA partially completed facilities, Luna and Moapa (See Note 13); a $64 million pre-tax correction of accounting errors related to the elimination of intercompany reserves at Bison (see Note 1); $45 million in taxes recorded in 2004 on the repatriation of foreign earnings that is expected to occur in 2005 associated with the American Jobs Creation Act of 2004 (see Note 6); a $51 million pre-tax charge related to the sale of DETM contracts that were held in a net liability position; $20 million in contract termination charges related to the DENA partially

126

completed plant at Grays Harbor (see Note 13); and approximately $42 million of impairment charges related to two Crescent residential developments in Payson, Arizona and one in Austin, Texas (See Note 12); and $8 million in bad debt charges recorded by Crescent related to notes receivable due from Rim Golf Investor LLC and Chaparral Pines Investor LLC. The bad debt charges are recorded in Operation, Maintenance and Other on the Consolidated Statement of Operations (See Note 12).

During the second quarter of 2003, Duke Energy recorded a $178 million pre-tax gain from the sale of DENA’s 50% interest in Ref-Fuel. (See Note 2).

During the third quarter of 2003, Duke Energy recorded the following unusual or infrequently occurring items: goodwill impairment related to DENA’s trading and marketing business of $254 million (see Note 10), severance charges of $105 million for work force reductions; a regulatory action by the PSCSC which resulted in decreased earnings of $46 million at Franchised Electric (see Note 4); a $52 million tax benefit related to International Energy’s goodwill impairment recognized in 2002 for the gas trading business in Europe; and a settlement with the Commodity Futures Trading Commission of $17 million, net of minority interest expense, by DENA.

During the fourth quarter of 2003, Duke Energy recorded the following unusual or infrequently occurring items: net $1.2 billion in asset impairment charges primarily related to DENA’s exit from the Southeast region and the related discontinuance of the Southeast region hedges (see Note 12); $1.7 billion in impairment charges related to DENA’s partially completed Western plants, related forward power and gas contracts that were de-designated as normal purchases and sales and hedges, a generation plant in Maine and the Morro Bay plant in California (see Note 13); charges and impairments of $292 million to complete International Energy’s exit from the European market and the divestiture of its Asia-Pacific Business; a $51 million write-off of an abandoned corporate risk management information system; severance charges of $48 million for workforce reductions; additional employee benefit expense of approximately $28 million; and right of way clearing costs of approximately $40 million at Franchised Electric.

23. Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-K for the year ended December 31, 2004, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

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

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

Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see also Note 3 to the Consolidated Financial Statements).

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

127

Acquisitions and Dispositions - DENA. As described in Note 13 to the Consolidated Financial Statements, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

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

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

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

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

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

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

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

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

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

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

Pro forma Cinergy Merger Transaction Value (unaudited)

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

128

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

Regulatory Matters - Franchised Electric. On March 9, 2005, Duke Power Company (Duke Power) filed with the North Carolina Utilities Commission a proposed fuel rate increase, for rates effective July 1, 2005 for a twelve-month period. To reduce the impact of the increased cost of fuel, Duke Power is seeking approval in the fuel case proceeding to credit the deferred fuel account by approximately $100 million for previously recorded excess deferred tax liabilities that are recorded as regulatory liabilities. The filing has not yet been approved. No similar action has yet been proposed to the PSCSC.

Debt and Credit Facilities. On March 1, 2005, notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. The bondholders were notified that these securities would be called on April 15, 2005, the earliest date at which these bonds can be redeemed.

Common Stock. In connection with the Field Services transactions discussed above, Duke Energy announced plans to periodically repurchase up to an aggregate of $2.5 billion of common stock over the next three years.

129

DUKE ENERGY CORPORATION

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts			Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2004:
Injuries and damages	$	1,319	$	8	$	2		$	60	$	1,269
Allowance for doubtful accounts		280		87		6			220		153
Other(b)		415		165		57			257		380
	$	2,014	$	260	$	65		$	537	$	1,802
December 31, 2003:
Injuries and damages	$	367	$	1	$	1,024	(d)	$	73	$	1,319
Allowance for doubtful accounts		349		65		16			150		280
Other(b)		513		183		18			299		415
	$	1,229	$	249	$	1,058		$	522	$	2,014
December 31, 2002:
Injuries and damages	$	459	$	14	$	5		$	111	$	367
Allowance for doubtful accounts		265		161		5			82		349
Other(b)		406		222		114	(c)		229		513
	$	1,130	$	397	$	124		$	422	$	1,229

(a) Principally cash payments and reserve reversals.

(b) Principally property insurance reserves and litigation and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(c) Includes the reclassification of $50 million of a $58 million suspense account to a nuclear insurance operation account in accordance with a settlement agreement between Duke Power, the NCUC and the PSCSC.

(d) Primarily represents changes in estimates for certain contingent liabilities which are covered by insurance and also recognized as an insurance receivable which is included in Other noncurrent assets on the Consolidated Balance Sheets.

130

Part IV, Exhibits and Financial Statement Schedule, Exhibit No. 12

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

The ratio of earnings to fixed charges is calculated using the Securities and Exchange Commission guidelines ^a.

(dollars in millions)

	Year Ended December 31,
	2004		2003			2002		2001		2000
Earnings as defined for fixed charges calculation
Add:
Pretax income (loss) from continuing operations b	$	1,824	$	(84	)	$	1,518	$	2,057	$	3,036
Fixed charges		1,370		1,570			1,469		1,082		1,070
Distributed income of equity investees		139		263			369		156		138
Deduct:
Preference security dividend requirements of consolidated subsidiaries		31		140			170		170		126
Interest capitalized c		18		58			139		101		49
Total earnings (as defined for the Fixed Charges calculation)	$	3,284	$	1,551		$	3,047	$	3,024	$	4,069
Fixed charges:
Interest on debt, including capitalized portions	$	1,301	$	1,390		$	1,259	$	878	$	917
Estimate of interest within rental expense		38		40			40		34		27
Preference security dividend requirements of consolidated subsidiaries		31		140			170		170		126
Total fixed charges	$	1,370	$	1,570		$	1,469	$	1,082	$	1,070
Ratio of earnings to fixed charges		2.4			d		2.1		2.8		3.8

^a Income Statement amounts have been adjusted for discontinued operations.

^b Excludes minority interest expenses and income or loss from equity investees.

^c Excludes equity costs related to Allowance for Funds Used During Construction that are included in Other Income and Expenses in the Consolidated Statements of Operations.

^d Earnings were inadequate to cover fixed charges by $19 million for the year ended December 31, 2003.

131

EX-99.2

Exhibit 99.2

Part I, Item 1. Financial Statements

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)

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

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

132

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

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

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

133

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

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

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

134

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2005 AND 2004

(Unaudited)

1. Basis of Presentation

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

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

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

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

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

2. Earnings Per Common Share (EPS)

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

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

(in millions, except per-share data)

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

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

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

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

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3. Common Stock

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

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

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

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

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

4. Stock-Based Compensation

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

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

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

5. Inventory

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

Inventory (in millions)

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

6. Debt and Credit Facilities

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

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

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

Available Credit Facilities and Restrictive Debt Covenants. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

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

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

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

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

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

(c) Credit facility contains an interest coverage covenant.

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

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

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

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

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

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

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

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

7. Employee Benefit Obligations

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

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

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

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

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

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

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

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

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

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

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

Total Comprehensive Income (in millions)

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

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

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

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

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

Components of and Changes in AOCI (in millions)

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

9. Acquisitions and Dispositions

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

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

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

142

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

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

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

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

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

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

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

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

In the first quarter of 2004, as a result of the marketing efforts related to DENA’s eight plants in the southeastern U.S., Duke Energy classified those assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million, which represented the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in Gains (Losses) on Sales of Other Assets, net in the first quarter 2004 Consolidated Statement of Operations. The fair value of the plants was based upon the anticipated price of approximately $475 million agreed upon with KGen Partners LLP (KGen) and announced on May 4, 2004. The sale closed in August 2004 and the actual sales price consisted of $420 million cash and a $48 million note receivable with principal and interest due no later than seven years and six months after the closing date. The entire balance of the note, including interest, was repaid by KGen in the first quarter of 2005. The agreement included the sale of all of Duke Energy’s merchant generation assets in the southeastern U.S. The results of operations related to these assets are not reported within Discontinued Operations due to Duke Energy’s significant continuing involvement in the future operations of the plants including a long-term operating agreement for one of the plants and retention of certain guarantees related to these assets.

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

10. Severance

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

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

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

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11. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations (in millions)

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

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

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

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

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Field Services

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

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

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

DENA

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

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

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

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

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

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

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

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

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

International Energy

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

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

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12. Business Segments

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

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

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

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

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

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).

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

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

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Business Segment Data (in millions)

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

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

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

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

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Segment Assets (in millions)

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

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

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

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

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13. Risk Management Instruments

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

Derivative Portfolio Carrying Value (in millions)

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

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

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

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

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

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

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

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

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

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

14. Regulatory Matters

Franchised Electric. Rate Related Information. The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC) approve rates for retail electric sales within their states. The Federal Energy Regulatory Commission (FERC) approves Franchised Electric’s rates for electric sales to regulated wholesale customers.

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

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

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

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

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

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

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

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

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

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

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

15. Commitments and Contingencies

Environmental

Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

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

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

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

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

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

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

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were accruals related to extended environmental-related activities of approximately $70 million as of March 31, 2005. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position.

Litigation

New Source Review (NSR)/EPA Litigation. In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a complaint against Duke Energy in the U.S. District Court in Greensboro, North Carolina, for alleged violations of the Clean Air Act (CAA). The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units were major modifications, as defined in the CAA, and that Duke Energy violated the CAA when it undertook those projects without obtaining permits and installing emission controls for SO2, NOx and particulate matter. The complaint asks the Court to order Duke Energy to stop operating the coal-fired units identified in the complaint, install additional emission controls and pay unspecified civil penalties.

Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy’s legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy. The government has appealed the case to the U.S. Fourth Circuit Court of Appeals. The Fourth Circuit heard oral argument on February 3, 2005. A decision is pending. Based on the current rulings by the trial court, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position. Subsequent rulings by the appellate court could significantly affect the outcome.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within noncurrent assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

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

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

16. Guarantees and Indemnifications

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

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

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

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

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

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

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

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

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

Other Guarantees and Indemnifications. Duke Capital LLC (Duke Capital), a wholly-owned subsidiary of Duke Energy, has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of March 31, 2005 was approximately $800 million. Of this amount, approximately $450 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $50 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2008 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

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

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

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

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

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

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

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

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

17. New Accounting Standards

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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18. Income Tax Expense

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

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

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

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

19. Subsequent Events

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

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Pro forma Cinergy Merger Transaction Value

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

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

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

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

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

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

INTRODUCTION

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

Overview of Business Strategy and Economic Factors

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

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

RESULTS OF OPERATIONS

Results of Operations and Variances (in millions)

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

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Overview of Drivers and Variances

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

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

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

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

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

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

Partially offsetting these increases and prior-year charges were:

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

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

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

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

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

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

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Consolidated Operating Revenues

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

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

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

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

Partially offsetting these increases in revenues were:

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

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

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

Consolidated Operating Expenses

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

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

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

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

Partially offsetting these increases in expenses were:

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

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

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

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

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

Consolidated Operating Income

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

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

Consolidated Other Income and Expenses, net

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

Consolidated Interest Expense

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

Consolidated Minority Interest Expense

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

Consolidated Income Tax Expense from Continuing Operations

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

Consolidated Income from Discontinued Operations, net of income tax

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

Segment Results

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

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

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

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

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

EBIT by Business Segment (in millions)

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

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

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

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

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Franchised Electric

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

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

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

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

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

Operating Revenues. The decrease was driven primarily by:

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

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

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

These decreases were partially offset by

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

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

Operating Expenses. The increase was driven primarily by:

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

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

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

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

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

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

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

Natural Gas Transmission

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

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

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

Operating Revenues. The increase was driven primarily by:

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

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

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

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

Operating Expenses. The increase was driven primarily by:

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

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

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

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

Field Services

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

a Trillion British thermal units per day

b Thousand barrels per day

c Million British thermal units

d Index-based market price

e Does not reflect results of commodity hedges.

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

Operating Revenues. The increase was primarily driven by:

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

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

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

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

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

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

Operating Expenses. The increase was driven primarily by:

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

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

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

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

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

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

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

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

Matters Impacting Future Field Services Results

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

DENA

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

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

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

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

• $45 million of power generation revenues, and

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

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

• $32 million of fuel costs

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

• $22 million of general and administrative expenses.

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

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

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

International Energy

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

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

Operating Revenues. The increase was driven primarily by:

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

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

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

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

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

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

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

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

Crescent

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

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

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

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

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

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

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

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

Other

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

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

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

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

Operating Revenues. The decrease was driven primarily by:

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

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

Operating Expenses. The decrease was driven primarily by:

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

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

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

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

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

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

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

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

Matters Impacting Future Other Results

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

Other Impacts on Earnings Available for Common Stockholders

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

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

Investing Cash Flows

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

Financing Cash Flows and Liquidity

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

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

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

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

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

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

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

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

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

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Credit Ratings Summary as of May 1, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy a	BBB	Baa1	Not applicable
Duke Capital LLC a	BBB-	Baa3	Not applicable
Duke Energy Field Services a	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP a	BBB	Baa2	Not applicable
Westcoast Energy Inc.	BBB	Not applicable	A(low)
Union Gas Limited a	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC b	A	A1	A
Maritimes & Northeast Pipeline, LP b	A	A1	A
Duke Energy Trading and Marketing, LLC c	BBB-	Not applicable	Not applicable

a Represents senior unsecured credit rating

b Represents senior secured credit rating

c Represents corporate credit rating

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, and a disciplined execution of the $2.5 billion share repurchase program, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.

Duke Energy and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Energy’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Energy’s collateral requirements. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participates in DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy.

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

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

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

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

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commercial Commitments

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

OTHER ISSUES

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

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

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

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

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

New Accounting Standards

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

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

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

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

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

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

Subsequent Events

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

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

• Acquisitions and Dispositions - Cinergy

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Pro forma Cinergy Merger Transaction Value

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

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

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

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

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

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

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

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

Commodity Price Risk

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

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

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

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Daily Earnings at Risk (in millions)

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

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

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

Credit Risk

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

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EX-99.3

Exhibit 99.3

Part I, Item 1. Financial Statements

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	3,303		$	2,905		$	6,206		$	5,744
Regulated electric		1,227			1,220			2,485			2,486
Regulated natural gas and natural gas liquids		744			675			1,911			1,696
Total operating revenues		5,274			4,800			10,602			9,926
Operating Expenses
Natural gas and petroleum products purchased		2,613			2,308			5,363			4,899
Operation, maintenance and other		894			749			1,702			1,483
Fuel used in electric generation and purchased power		392			471			741			883
Depreciation and amortization		462			394			943			803
Property and other taxes		145			118			298			263
Impairment and other charges		2			—			123			—
Total operating expenses		4,508			4,040			9,170			8,331
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		12			62			54			121
(Losses) Gains on Sales of Other Assets, net		—			(11	)		9			(350	)
Operating Income		778			811			1,495			1,366
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		39			43			80			77
Gains on sales and impairments of equity investments		6			—			1,245			—
Other income and expenses, net		35			50			59			82
Total other income and expenses		80			93			1,384			159
Interest Expense		295			312			585			655
Minority Interest Expense		78			44			498			84
Earnings From Continuing Operations Before Income Taxes		485			548			1,796			786
Income Tax Expense from Continuing Operations		157			142			608			218
Income From Continuing Operations		328			406			1,188			568
Discontinued Operations
Net operating loss, net of tax		(27	)		(1	)		(34	)		(92	)
Net gain on dispositions, net of tax		8			27			23			267
(Loss) Income From Discontinued Operations		(19	)		26			(11	)		175
Net Income		309			432			1,177			743
Dividends and Premiums on Redemption of Preferred and Preference Stock		2			3			4			5
Earnings Available For Common Stockholders	$	307		$	429		$	1,173		$	738
Common Stock Data
Weighted-average shares outstanding
Basic		927			926			941			919
Diluted		964			961			977			954
Earnings per share (from continuing operations)
Basic	$	0.35		$	0.43		$	1.26		$	0.61
Diluted	$	0.34		$	0.42		$	1.21		$	0.60
(Loss) Earnings per share (from discontinued operations)
Basic	$	(0.02	)	$	0.03		$	(0.01	)	$	0.19
Diluted	$	(0.02	)	$	0.03		$	(0.01	)	$	0.18
Earnings per share
Basic	$	0.33		$	0.46		$	1.25		$	0.80
Diluted	$	0.32		$	0.45		$	1.20		$	0.78
Dividends per share	$	0.585		$	0.550		$	0.860		$	0.825

See Notes to Consolidated Financial Statements for the Three and Six Months Ended June 30, 2005 and 2004

187

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

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

See Notes to Consolidated Financial Statements for the Three and Six Months Ended June 30, 2005 and 2004

188

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

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

See Notes to Consolidated Financial Statements for the Three and Six Months Ended June 30, 2005 and 2004

189

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

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

See Notes to Consolidated Financial Statements for the Three and Six Months Ended June 30, 2005 and 2004

190

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004

(Unaudited)

1. Basis of Presentation

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

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

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

Reclassifications and Other Changes. The accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2004 reflects a reclassification of instruments used in Duke Energy’s cash management program from cash and cash equivalents to short-term investments of $1,684 million and $763 million as of June 30, 2004 and December 31, 2003, respectively. This reclassification was made in order to present certain auction rate securities and other highly-liquid instruments as short-term investments rather than as cash equivalents due to the stated tenor of the maturities of these investments.

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

Certain other prior period amounts have also been reclassified to conform to the presentation for the current period. Such reclassifications include the reclassification of the results of certain operations from continuing operations to discontinued operations (see Note 11). Except as required to reflect the effects of the Duke Energy North America (DENA) discontinued operations classification discussed in Note 11 and the segment changes discussed in Note 12, the financial statements have not been otherwise modified or updated from those presented in Duke Energy’s For 10-Q for the quarter ended June 30, 2005. These changes impacted Note 2, Note 9, Note 11, Note 12 and Note 19.

2. Earnings Per Common Share (EPS)

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

191

The following tables illustrate Duke Energy’s basic and diluted EPS calculations for income from continuing operations and reconcile the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and six months ended June 30, 2005 and 2004.

	Income			Average Shares	EPS
	(in millions, except per-share data)
Three Months Ended June 30, 2005
Income from continuing operations	$	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 restricted stock, and common stock derivatives				4
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	328		964	$	0.34
Three Months Ended June 30, 2004
Income from continuing operations	$	406
Less: Dividends and premiums on redemption of preferred and preference stock		(3	)
Income from continuing operations—basic	$	403		926	$	0.43
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		2		33
Income from continuing operations—diluted	$	405		961	$	0.42
Six Months Ended June 30, 2005
Income from continuing operations	$	1,188
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 restricted stock, and common stock derivatives				3
Contingently convertible bond		4		33
Income from continuing operations—diluted	$	1,188		977	$	1.21
Six Months Ended June 30, 2004
Income from continuing operations	$	568
Less: Dividends and premiums on redemption of preferred and preference stock		(5	)
Income from continuing operations—basic	$	563		919	$	0.61
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		4		33
Income from continuing operations—diluted	$	567		954	$	0.60

192

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

As a result of adopting the provisions of Emerging Issues Task Force (EITF) Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” as discussed in Note 17, Duke Energy has restated diluted earnings per share for the three months ended June 30, 2004, from $0.46 to $0.45, and restated diluted earnings per share for the six months ended June 30, 2004, from $0.80 to $0.78.

Options, restricted stock, performance and phantom stock awards related to approximately 18 million shares as of June 30, 2005, and 26 million shares as of June 30, 2004, were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

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

3. Common Stock

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

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

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

Duke Energy accounted for the forward sale contract under the provisions of EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock,” as an equity instrument. As the fair value of the forward sale contract at inception was zero, no accounting for the forward sale contract will be required, until settlement, as long as the forward sale contract continues to meet the requirements for classification as an equity instrument. Any amounts (cash or shares) either paid or received at settlement of the contract will be recorded in Common Stockholders’ Equity. As of June 30, 2005, the investment bank had purchased approximately 20.4 million shares at a weighted average price of $28.28 per share.

Duke Energy also entered into a separate open market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. Duke Energy may terminate this plan at any time, without penalty. The timing of any repurchase of shares by the investment bank pursuant to this plan is dependent upon certain specified factors, including the market price of Duke Energy’s common stock. As of June 30, 2005, Duke Energy had purchased approximately 2.6 million shares of its common stock pursuant to this plan at a weighted average price of $28.97 per share. On May 9, 2005, in connection with the proposed merger with Cinergy Corp. (Cinergy), Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. (For further discussion, see Note 9.)

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

193

4. Stock-Based Compensation

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

Pro Forma Stock-Based Compensation

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

5. Inventory

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

Inventory

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

194

6. Debt and Credit Facilities

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

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

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

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

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

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

195

Credit Facilities Summary as of June 30, 2005

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

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

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

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

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

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

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

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

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

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

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

(k) Credit facility contains an interest coverage covenant.

196

7. Employee Benefit Obligations

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

Components of Net Periodic Pension Costs (Income)

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

Duke Energy’s policy is to fund amounts for its U.S. retirement plan on an actuarial basis to provide sufficient assets to meet benefit payments to plan participants. Duke Energy has not made contributions to its U.S. retirement plan for the three and six month periods ended June 30, 2005 and does not anticipate making a contribution to the U.S. retirement plan for the remainder of 2005.

Westcoast’s policy is to fund its defined benefit (DB) retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefit payments. Contributions to the defined contribution (DC) retirement plans are determined in accordance with the terms of the plans. Duke Energy has contributed $8 million and $19 million to the Westcoast DB plans for the three and six month periods ended June 30, 2005, respectively. Duke Energy anticipates that it will make total contributions of approximately $37 million in 2005. Duke Energy has contributed $1 million and $2 million to the Westcoast DC plans for the three and six month periods ended June 30, 2005, respectively, and anticipates that it will make total contributions of approximately $3 million in 2005.

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

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Components of Net Periodic Post-Retirement Benefit Costs

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

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

8. Comprehensive Income and Accumulated Other Comprehensive Income

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

Total Comprehensive Income

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

(a) Foreign currency translation adjustments, net of $62 million tax benefit for the six months ended June 30, 2005, related to the settled net investment hedges (see Note 13). This tax benefit is an immaterial correction of an accounting error related to prior periods.

(b) Net unrealized gains on cash flow hedges, net of $49 million and $14 million tax expense for the three months ended June 30, 2005 and 2004, respectively, and $123 million and $66 million tax expense for the six months ended June 30, 2005 and 2004, respectively.

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

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

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Components of and Changes in AOCI

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

9. Acquisitions and Dispositions

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

On May 9, 2005, Duke Energy and Cinergy announced they have entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $4 billion. The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. See further discussion of regulatory filings in Note 14. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

In April 2005, Duke Energy’s Natural Gas Transmission business unit agreed to acquire natural gas storage and pipeline assets in southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. Upon closing of this transaction, which is expected to occur in the third quarter of 2005, Natural Gas Transmission will own 100% of Saltville Storage.

In the second quarter 2005, United Bridgeport Energy, LLC (UBE), the owner of a 33 ¹/3% interest in Bridgeport Energy, LLC (Bridgeport), exercised its “put right” requiring DENA to purchase UBE’s interest in Bridgeport as provided for in the LLC Agreement. DENA and UBE are currently negotiating the purchase price of UBE’s ownership interest. Upon closing of this transaction, DENA will own 100% of Bridgeport. The assets and liabilities of Bridgeport will be included as part of the divestiture of DENA’s power generation assets in the eastern United States (see Note 11).

Dispositions. 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 Gains on Sales of Equity Investments on the Consolidated Statements of Operations. For the six months ended June 30, 2005, the sale of other assets, businesses and equity 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, net and pre-tax gains of approximately $1.2 billion recorded in Gains on Sales of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 11, and commercial and multi-family real estate sales by Crescent Resources LLC (Crescent) which are discussed separately below. Significant sales of other assets and equity investments during the six months ended June 30, 2005 are detailed as follows:

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

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion in cash and assets from ConocoPhillips and DEFS. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities (see Note 12). Additionally, the DEFS disposition transaction, as previously announced, was anticipated to include ConocoPhillips’ interest in the Empress System gas processing and natural gas liquids marketing business (Empress System). However, the transfer of the Empress System to Duke Energy was delayed pending damage repairs to the assets from a recent windstorm and as a result ConocoPhillips has transferred an equivalent value of cash to Duke Energy in July 2005. The Empress System was subsequently transferred to Duke Energy in August 2005 and cash of approximately $230 million was remitted to ConocoPhillips as consideration for the transfer. Subsequent to the DEFS disposition transaction, DEFS will no longer be consolidated into Duke Energy’s historical consolidated financial statements and will be accounted for by Duke Energy as an equity method investment. See Note 13 for the impacts of this transaction on certain cash flow hedges. The DEFS Canadian natural gas gathering and processing facilities and the Empress System will be included in Duke Energy’s Natural Gas Transmission business unit.

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

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

For the three months ended June 30, 2004, the sale of other assets resulted in approximately $39 million in proceeds, and net losses of $11 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. For the six months ended June 30, 2004, the sale of other assets resulted in approximately $142 million in proceeds, and net losses of $350 million recorded in (Losses) Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. Significant sales of other assets and equity investments during the six months ended June 30, 2004 are as follows:

• As a result of the marketing efforts related to DENA’s eight plants in the southeastern U.S., Duke Energy classified those assets and associated liabilities as held for sale in the Consolidated Balance Sheet at March 31, 2004 and recorded a pre-tax loss on these assets of approximately $360 million in the first quarter of 2004, which represented the excess of the carrying value over the fair value of the plants, less costs to sell. This loss was included in (Losses) Gains on Sale of Other Assets, net in the first quarter of 2004 Consolidated Statement of Operations. The fair value of the plants was based upon the anticipated price of approximately $475 million agreed upon with KGen Partners LLP (KGen) and announced on May 4, 2004. The sale closed in August 2004 and the actual sales price consisted of $420 million cash and a $48 million note receivable with principal and interest due no later than seven years and six months after the closing date. The entire balance of the note, including interest, was repaid by KGen in the first quarter of 2005. The agreement included the sale of all of Duke Energy’s merchant generation assets in the southeastern U.S. The results of operations related to these assets are not reported within Discontinued Operations due to Duke Energy’s significant continuing involvement in the future operations of the plants including a long-term operating agreement for one of the plants and retention of certain guarantees related to these assets.

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

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

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

10. Severance

During 2002, Duke Energy communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and will apply to individuals notified of layoffs between that date and January 1, 2006. As of June 30, 2005, there are no significant remaining amounts to be paid under these severance plans. Provision for severance is included in Operation, Maintenance and Other in the Consolidated Statements of Operations.

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11. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations (in millions)

			Net Operating Income									Net Gain on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax
Three Months Ended June 30, 2005
DENA	$	386	$	(27	)	$	—		$	(27	)	$	(1	)	$	(9	)	$	8
International Energy		—		2			2			—			—			—			—
Total consolidated	$	386	$	(25	)	$	2		$	(27	)	$	(1	)	$	(9	)	$	8
Three Months Ended June 30, 2004
Field Services	$	15	$	(1	)	$	(1	)	$	—		$	—		$	—		$	—
DENA		573		(8	)		(10	)		2			(3	)		—			(3	)
International Energy		17		(2	)		2			(4	)		39			9			30
Other		1		2			1			1			—			—			—
Total consolidated	$	606	$	(9	)	$	(8	)	$	(1	)	$	36		$	9		$	27
Six Months Ended June 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—
DENA		877		(48	)		(13	)		(35	)		23			—			23
International Energy		—		4			3			1			—			—			—
Total consolidated	$	881	$	(44	)	$	(10	)	$	(34	)	$	23		$	—		$	23
Six Months Ended June 30, 2004
Field Services	$	51	$	1		$	—		$	1		$	2		$	1		$	1
DENA		1,175		(149	)		(53	)		(96	)		(2	)		—			(2	)
International Energy		82		3			1			2			295			27			268
Other		1		2			1			1			—			—			—
Total consolidated	$	1,309	$	(143	)	$	(51	)	$	(92	)	$	295		$	28		$	267

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004.

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

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

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Field Services

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

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

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

DENA

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets (see Note 9 for further details on the anticipated Cinergy merger). The exit plan is expected to be completed by the end of the third quarter of 2006. In addition, management will continue to wind down the limited remaining operations of DETM. The DENA assets to be divested include:

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

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

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

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

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, as discussed further in Note 2, DENA’s Southeastern generation operations, including related commodity contracts do not qualify for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

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

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

On September 21, 2004, DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving would purchase DENA’s 75% interest in Bayside Power L.P. (Bayside). As a result of the above agreement, DENA presented the $54 million of assets and $14 million of liabilities as of June 30, 2005 and $59 million of assets and $19 million of liabilities as of December 31, 2004 related to Bayside as Assets Held For Sale in the Consolidated

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Balance Sheets. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was approximately $20 million at June 30, 2005 and $19 million at December 31, 2004. Bayside was consolidated with the adoption of FASB Interpretation (FIN) No. 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51”, on March 31, 2004. Therefore, Bayside’s operating results after March 31, 2004 are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment. The sale of Bayside closed on July 13, 2005. The after-tax gain on this sale will be included in Discontinued Operations-Net Gain on Dispositions, net of tax, in the Consolidated Statements of Operations in the third quarter of 2005.

International Energy

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

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

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

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

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

Crescent

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

Other

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

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12. Business Segments

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

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

As discussed further in Note 11, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended June 30, 2005 increased Other’s segment losses by approximately $30 million. For the six months ended June 30, 2005, the inclusion of DENA’s continuing operations increased Other’s segment losses by approximately $60 million. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

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

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

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

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).

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

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

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Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Three Months Ended June 30, 2005
Franchised Electric	$	1,229	$	5		$	1,234		$	274
Natural Gas Transmission		720		44			764			304
Field Services		2,895		(23	)		2,872			165
International Energy		182		—			182			86
Crescent		112		—			112			38
Total reportable segments		5,138		26			5,164			867
Other(a)		136		45			181			(118	)
Eliminations		—		(71	)		(71	)		—
Interest expense		—		—			—			(295	)
Interest income and other (b)		—		—			—			31
Total consolidated	$	5,274	$	—		$	5,274		$	485
Three Months Ended June 30, 2004
Franchised Electric	$	1,222	$	6		$	1,228		$	338
Natural Gas Transmission		668		35			703			315
Field Services		2,343		(18	)		2,325			92
DENA(a)		69		8			77			(57	)
International Energy		147		—			147			68
Crescent		101		—			101			87
Total reportable segments		4,550		31			4,581			843
Other		250		40			290			(26	)
Eliminations		—		(71	)		(71	)		—
Interest expense		—		—			—			(312	)
Interest income and other (b)		—		—			—			43
Total consolidated	$	4,800	$	—		$	4,800		$	548

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

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

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Business Segment Data

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes
	(in millions)
Six Months Ended June 30, 2005
Franchised Electric	$	2,489	$	10		$	2,499		$	610
Natural Gas Transmission		1,875		80			1,955			715
Field Services		5,470		60			5,530			1,083
International Energy		350		—			350			154
Crescent		176		—			176			90
Total reportable segments		10,360		150			10,510			2,652
Other(a)		242		(14	)		228			(320	)
Eliminations		—		(136	)		(136	)		—
Interest expense		—		—			—			(585	)
Interest income and other (b)		—		—			—			49
Total consolidated	$	10,602	$	—		$	10,602		$	1,796
Six Months Ended June 30, 2004
Franchised Electric	$	2,488	$	11		$	2,499		$	762
Natural Gas Transmission		1,680		76			1,756			717
Field Services		4,695		(31	)		4,664			180
DENA(a)		74		20			94			(487	)
International Energy		301		—			301			97
Crescent		139		—			139			147
Total reportable segments		9,377		76			9,453			1,416
Other		549		85			634			(31	)
Eliminations		—		(161	)		(161	)		—
Interest expense		—		—			—			(655	)
Interest income and other (b)		—		—			—			56
Total consolidated	$	9,926	$	—		$	9,926		$	786

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

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

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

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Segment Assets

	June 30, 2005			December 31, 2004
	(in millions)
Franchised Electric	$	18,066		$	18,199
Natural Gas Transmission		17,466			17,498
Field Services		7,196			6,436
DENA (a)		5,418			6,719
International Energy		3,576			3,329
Crescent		1,478			1,315
Total reportable segments		53,200			53,496
Other		3,394			1,829
Reclassifications and eliminations (b)		(599	)		145
Total consolidated assets	$	55,995		$	55,470

^(a) DENA’s segment assets include the assets for DENA’s discontinued operations as of June 30, 2005 (see Note 11).

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

Segment assets include goodwill of $4,106 million as of June 30, 2005 and $4,148 million as of December 31, 2004, with $3,361 million allocated to Natural Gas Transmission, $478 million to Field Services, $260 million to International Energy and $7 million to Crescent as of June 30, 2005. The $42 million decrease from December 31, 2004 to June 30, 2005 was related solely to foreign currency exchange rate fluctuations of $55 million at Natural Gas Transmission and $2 million at Field Services, partially offset by an increase of $15 million at International Energy.

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13. Risk Management Instruments

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

Derivative Portfolio Carrying Value

	June 30, 2005			December 31, 2004
	(in millions)
Hedging	$	1,294		$	795
Trading		(7	)		18
Undesignated		(353	)		(262	)
Total	$	934		$	551

The amounts in the table above represent the combination of assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Energy’s Consolidated Balance Sheets. All amounts represent current fair value, except that the net asset amounts for hedging include assets of $94 million as of June 30, 2005 and $160 million as of December 31, 2004, that were frozen upon Duke Energy’s initial application of the normal purchases and normal sales exception to its forward power sales contracts as of July 1, 2001. These asset values will amortize as they settle over approximately five years.

The $499 million increase in the hedging derivative portfolio carrying value is due primarily to increases in forward natural gas prices, partially offset by the realization of natural gas hedge gains as well as other hedge activity.

The $91 million decrease in the undesignated derivative portfolio fair value is due primarily to mark-to-market of certain contracts held by Duke Energy related to Field Services’ commodity price risk. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see Note 9), Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. As a result, approximately $120 million of unrealized pre-tax losses previously recorded in AOCI related to these contracts has been recognized in earnings by Duke Energy in the six months ended June 30, 2005. These charges have been classified as a component of Impairment and Other Charges in the Consolidated Statement of Operations. Since discontinuance of hedge accounting, these contracts have been marked-to market in the Consolidated Statement of Operations, resulting in the recognition of approximately $20 million and $130 million of additional realized and unrealized pre-tax losses, classified as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other Revenues in the Consolidated Statement of Operations for the three and six months ended June 30, 2005, respectively. The decrease in the undesignated derivative portfolio fair value is partially offset by certain contract terminations at DENA.

Included in Other Current Assets in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are collateral assets of approximately $636 million and $300 million, respectively, which represents cash collateral posted by Duke Energy with other third parties. This increase in cash collateral posted by Duke Energy is primarily due to increases in crude oil prices as well as increases to the forward market prices of power. Included in Other Current Liabilities in the Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 are collateral liabilities of approximately $533 million and $523 million, respectively, which represents cash collateral posted by other third parties to Duke Energy.

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

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

As of June 30, 2005, $436 million of the pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

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The ineffective portion of commodity cash flow hedges resulted in the recognition of a loss of approximately $11 and $30 million in the three and six months ended June 30, 2005, respectively, as compared to a gain of $3 and $5 million in the three and six months ended June 30, 2004, respectively.

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

14. Regulatory Matters

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

Franchised Electric. Rate Related Information. NCUC and PSCSC approve rates for retail electric sales within their states. FERC approves Franchised Electric’s rates for electric sales to regulated wholesale customers.

In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). Franchised Electric’s amortization expense related to this clean air legislation totals $482 million from inception, with $156 million recorded for the first six months of 2005 and $33 million recorded for the first six months of 2004. As of June 30, 2005, cumulative expenditures totaled $249 million, with $125 million incurred for the first six months of 2005 and $21 million incurred for the first six months of 2004, and are included in Net Cash Provided by (Used in) Investing Activities on the Consolidated Statements of Cash Flows. Duke Energy has changed the classification of these expenditures for clean air legislation from cash flows used in operating activities to cash flows used in investing activities, as discussed in Note 1. Based upon current estimates on file with the NCUC, Franchised Electric estimates total cost of complying with the clean air legislation to be approximately $1.7 billion, which is an increase of $200 million from previous estimates of approximately $1.5 billion.

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

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

In October 2004, Duke Power filed the results of a funding study for nuclear decommissioning costs with the NCUC and in December 2004, Duke Power notified the PSCSC of the results of the funding study. A NCUC decision on the appropriate level of decommissioning funding was received in July 2005 at the requested $48 million annual amount.

Over-Accrued Deferred Taxes. On March 9, 2005, Duke Power filed with the NCUC a proposed fuel rate increase, for rates effective July 1, 2005 for a 12-month period. To reduce the impact of the increased cost of fuel, Duke Power requested approval in the fuel case proceeding to flow to customers approximately $100 million in revenue requirement for previously recorded excess deferred tax liabilities that are recorded as regulatory liabilities in the form of a rate decrement. On June 15, 2005, the NCUC approved Duke Power’s proposed fuel rate and deferred tax decrement. Duke Power proposed a similar action to the PSCSC in its fuel rate adjustment filing in July 2005 for the South Carolina portion of approximately $40 million.

Market-Based Rate Authority. FERC has instituted a rulemaking process to modify its methodology to assess generation market power. In the interim, FERC has established certain market screens. Failure to satisfy any of those screens requires an applicant for market-based rates to submit additional tests and information to FERC to demonstrate that it does not have generation market power in the region in which it fails the screens. Some of the screens which do not subtract obligations to

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serve native load are difficult for a franchised utility such as Duke Power to pass. In an order issued on June 30, 2005, the FERC revoked the authority for Duke Power to make wholesale power sales within its control area at market-based rates based on the FERC’s determination that Duke Power fails one of the applicable market screens. Under the FERC’s order, Duke Power must pay partial refunds and may prospectively make wholesale power sales within its control area only at cost-based rates. The FERC’s order is not expected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position. Pursuant to a previous order, Duke Power may continue to make wholesale sales at market-based rates to customers outside of its control area.

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

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

Rate Related Information. In December 2004, the Ontario Energy Board (OEB) approved the 2005 rates for Union Gas. The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the 9.63% benchmark return on equity (ROE), normalized for weather, will be shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below the allowed ROE, normalized for weather. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $8 million during the six months ended June 30, 2005.

The OEB also directed Union Gas to provide direction as to how it will proceed with setting 2006 rates, including the use of an earnings sharing mechanism. Union Gas responded to this directive by recommending the use of the same earnings sharing mechanism as found appropriate by the Board for 2005 rates, with a request for a rate increase. The OEB indicated in May 2005 that it was prepared to consider Union Gas’ request, but required an application and supporting evidence, which Union Gas provided to the OEB on July 29, 2005.

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

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement has been filed with FERC for its review and approval. FERC is expected to act on the settlement agreement prior to the end of 2005.

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

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

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15. Commitments and Contingencies

Environmental

Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

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

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina, and its three natural gas-fired generating facilities in California are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to provide information needed to determine necessary facility-specific modifications and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures are determined and approved by regulators, a facility will typically have five or more years to implement the measures. Due to the wide range of measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Energy is not able to estimate its cost for complying with the rule at this time.

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

Clean Air Mercury Rule. The EPA’s final Clean Air Mercury Rule (CAMR) was published in the Federal Register May 18, 2005. The rule limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. Phase 1 begins in 2010 and Phase 2 begins in 2018. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAMR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAMR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAMR.

Clean Air Interstate Rule. The EPA’s final Clean Air Interstate Rule (CAIR) was published in the Federal Register May 12, 2005. The rule limits total annual SO₂ and NOx emissions from electric generating facilities across the eastern United States through a two-phased cap-and-trade program. Phase 1 begins in 2009 for NOx and in 2010 for SO₂. Phase 2 begins in 2015 for both NOx and SO₂. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAIR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAIR. On July 11, 2005, Duke Energy and others filed petitions with the U.S. Court of Appeals for the District of Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy is seeking to have the EPA revise the method of allocating SO₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $65 million as of June 30, 2005. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows, or financial position.

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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 has filed a petition for rehearing with the Fourth Circuit, and may seek further appellate review. Based on the current rulings, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position. Subsequent rulings by the appellate courts could significantly affect the outcome.

Western Energy Litigation. Since 2000, plaintiffs have filed 48 lawsuits in four western states against Duke Energy affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Eleven suits have been dismissed on filed rate and/or federal preemption grounds. The plaintiffs in these dismissed suits appealed, and the U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit petitioned the U.S. Supreme Court for certiorari and the Court invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted. On May 27, 2005, the U.S. Solicitor General recommended that certiorari be denied. On June 27, 2005, the U.S. Supreme Court denied certiorari.

• In July 2004, Duke Energy reached an agreement in principle resolving the class-action litigation involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement is part of a more comprehensive settlement involving FERC refunds and other proceedings related to the western energy markets during 2000-2001 (the California Settlement). The class action portion of the settlement was subject to court approval, but FERC approved all remaining provisions of the settlement in December 2004. As part of the California Settlement, Duke Energy agreed to provide approximately $208 million in cash and credits to various parties involved in the settlement. The parties agreed to forgo all claims relating to refunds or other monetary damages for sales of electricity during the settlement period (January 1, 2000 through June 20, 2001), and claims alleging Duke Energy received unjust or unreasonable rates for the sale of electricity during the settlement period. In December 2004, Duke Energy tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. This remaining amount, which is fully reserved, will be paid upon court approval of the class-action settlement. On July 22, 2005, the Superior Court for San Diego County entered an order granting preliminary approval of the class-action settlement and authorizing notice of the proposed settlements to be sent to the respective class members. A hearing on final approval of the class-action settlements is presently scheduled for December 2005.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within Investments and Other Assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and

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Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

Duke Energy has exposure to certain legal matters that are described herein. As of June 30, 2005, Duke Energy has recorded reserves of approximately $1.4 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of June 30, 2005, Duke Energy has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

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

16. Guarantees and Indemnifications

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

Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the prime contractor to the U.S. Department of Energy (DOE) under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of June 30, 2005, Duke Energy, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

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

DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Energy estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of June 30, 2005, Duke Energy had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.

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

DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. DPSG has recourse to the other owners of DCS for any amounts paid under the Duke Power Guarantee in excess of its proportional ownership percentage of DCS. Even though the Duke Power Guarantee does not provide for a specific limitation on a guarantor’s

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guarantee obligations, it does provide that any liability of such guarantor under the Duke Power Guarantee is directly related to and limited by the terms and conditions in the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Duke Power Subcontract. Duke Energy is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the Duke Power Guarantee due to the uncertainty of whether:

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

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

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

Other Guarantees and Indemnifications. Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of June 30, 2005 was approximately $800 million. Of this amount, approximately $400 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $50 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2007 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of June 30, 2005 was approximately $60 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of June 30, 2005 was approximately $500 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities. Of those letters of credit, approximately $225 million expire in 2005, with the remainder expiring in 2006.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of June 30, 2005, Duke Capital had guaranteed approximately $15 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2005 and 2006. Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of June 30, 2005, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly-owned entities. Of those guarantees, approximately $5 million expire in 2005, with the remainder expiring in 2006 and 2007.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity

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discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2005 to 2019, with others having no specific term. Duke Energy is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

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

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

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

17. New Accounting Standards

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

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

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. The after-tax effect on net periodic post-retirement benefit cost resulted in a decrease of $12 million for the year ended December 31, 2004 and will result in a decrease of $12 million for the year ended December 31, 2005.

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

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

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

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

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus in Issue No. 03-13 also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus in EITF Issue No. 03-13 was effective for Duke Energy beginning January 1, 2005. The impact to Duke Energy of adopting EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Energy does not currently expect EITF Issue No. 03-13 will have a material impact on its consolidated results of operations, cash flows or financial position.

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of June 30, 2005:

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

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

The impact on EPS for the three and six month periods ended June 30, 2005 and 2004 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed in the Pro Forma Stock-Based Compensation table included in Note 4. Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has

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Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Energy does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

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

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

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

18. Income Tax Expense

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

Under the guidance in FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. In the first six months of 2005, Duke Energy recognized a benefit of approximately $3 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on the decision, Duke Energy plans to repatriate approximately $500 million in extraordinary dividends in 2005, as defined in the Act, and accordingly recorded a corresponding tax liability of $45 million as of December 31, 2004. During the second quarter of 2005, Duke Energy reorganized various entities which enabled the company to reduce the $45 million tax liability to $41 million. No extraordinary dividends were repatriated during the six months ended June 30, 2005. Duke Energy repatriated approximately $200 million of extraordinary dividends in July 2005.

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Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes have been made for potential liabilities resulting from these matters. As of June 30, 2005, Duke Energy had total provisions of approximately $144 million for uncertain tax positions, as compared to $149 million as of December 31, 2004, including interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

19. Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-Q for the quarter ended June 30, 2005, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

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

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

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

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

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

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

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

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

In addition to these amounts, at September 30, 2005, approximately $150 million of pre-tax deferred net gains remain in AOCI related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings over the next 12 months as the forecasted transactions occur. In addition,

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management anticipates that additional charges will be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts estimated at approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs. The actual amount of future additional charges related to the DENA exit plan will vary depending on changes in market conditions and other factors, and could differ from management’s current expectation.

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

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

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

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

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

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

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

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

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the Three and Six Months Ended June 30, 2005 and 2004.

Overview of Business Strategy and Economic Factors

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

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

RESULTS OF OPERATIONS

Results of Operations and Variances

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	5,274		$	4,800		$	474		$	10,602		$	9,926		$	676
Operating expenses		4,508			4,040			468			9,170			8,331			839
Gains on sales of investments in commercial and multi-family real estate		12			62			(50	)		54			121			(67	)
(Losses) gains on sales of other assets, net		—			(11	)		11			9			(350	)		359
Operating income		778			811			(33	)		1,495			1,366			129
Other income and expenses, net		80			93			(13	)		1,384			159			1,225
Interest expense		295			312			(17	)		585			655			(70	)
Minority interest expense		78			44			34			498			84			414
Earnings from continuing operations before income taxes		485			548			(63	)		1,796			786			1,010
Income tax expense from continuing operations		157			142			15			608			218			390
Income from continuing operations		328			406			(78	)		1,188			568			620
(Loss) income from discontinued operations, net of tax		(19	)		26			(45	)		(11	)		175			(186	)
Net income		309			432			(123	)		1,177			743			434
Dividends and premiums on redemption of preferred and preference stock		2			3			(1	)		4			5			(1	)
Earnings available for common stockholders	$	307		$	429		$	(122	)	$	1,173		$	738		$	435

Overview of Drivers and Variances

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

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$0.45 per diluted share. Significant items that contributed to decreased earnings available for common stockholders for the quarter included:

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

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

• A $45 million after-tax decrease from discontinued operations driven primarily by a $40 million after-tax gain recorded in the second quarter 2004 related to the sale of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business) and an $18 million after-tax unfavorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market gains associated with the disqualified hedge positions around the partially completed western plants in 2004, which were classified as discontinued operations as a result of the DENA exit plan, partially offset by a $9 million after-tax charge on International Energy’s European gas trading and marketing business (the European Business). DENA’s 2004 gain related to the settlement of the Enron bankruptcy proceedings was entirely offset by a charge related to the California and western U.S. energy markets settlement (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”)

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

• A $15 million increase in income tax expense from continuing operations, resulting primarily from a release of various income tax reserves in the second quarter 2004 totaling approximately $52 million, partially offset by lower income from continuing operations in 2005.

Partially offsetting these amounts were:

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

• A $17 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004.

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

• An $802 million pre-tax gain (net of minority interest of $343 million) recorded in 2005 on the sale of DEFS’s wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, L.P. (TEPPCO LP), an equity method investment of DEFS

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

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

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

• A $70 million pre-tax decrease in interest expense, due primarily to Duke Energy’s debt reduction efforts in 2004

• An approximate $65 million pre-tax increase in earnings (net of minority interest of $13 million) from DENA’s continuing operations due primarily to lower operating and general and administrative expenses, partially offset by lower power generation sales as a result of the sale of the Southeast Plants in 2004, and

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

Partially offsetting these amounts were:

• A $390 million increase in income tax expense from continuing operations, resulting primarily from higher earnings, primarily the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, discussed above, and the release of various income tax reserves in the second quarter 2004 totaling approximately $52 million

• An approximate $250 million of unrealized pre-tax losses recognized in 2005 on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”)

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• A $186 million after-tax decrease in income from discontinued operations driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business, partially offset by an $86 million after-tax favorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified as discontinued operations as a result of the DENA exit plan, and a $9 million after-tax charge on International Energy’s European Business. DENA’s 2004 gain related to the settlement of the Enron bankruptcy proceedings was entirely offset by a charge related to the California and western U.S. energy markets settlement (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”)

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

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

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

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

Consolidated Operating Revenues

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating revenues for the three months ended June 30, 2005 increased $474 million, compared to the same period in 2004. This change was driven primarily by:

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

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

• An approximate $46 million increase due principally to higher energy prices and volumes at International Energy and higher residential developed lot sales at Crescent.

Partially offsetting these increases in revenues were:

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

• A $44 million decrease from DENA’s continuing operations, due primarily to the sale of the Southeast Plants in 2004 and the continued wind-down of Duke Energy Trading and Marketing, LLC (DETM, Duke Energy’s 60/40 joint venture with ExxonMobil Corporation).

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating revenues for the six months ended June 30, 2005 increased $676 million, compared to the same period in 2004. This change was driven primarily by:

• An $866 million increase at Field Services due primarily to higher average commodity prices, primarily NGL and natural gas, in 2005

• A $199 million increase at Natural Gas Transmission due primarily to higher natural gas prices that are passed through to customers and favorable foreign exchange rates as a result of the strengthening Canadian dollar (mostly offset by gas price and currency impacts to expenses)

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

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

Partially offsetting these increases in revenues were:

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

• An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”), and

• A $52 million decrease from DENA’s continuing operations, due primarily to the sale of the Southeast Plants in 2004 and the continued wind-down of DETM.

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

Consolidated Operating Expenses

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating expenses for the three months ended June 30, 2005 increased $468 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $500 million increase in operating expenses at Field Services and Natural Gas Transmission driven primarily by higher average NGL and natural gas prices, and foreign exchange impacts, and

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

Partially offsetting these increases in expenses were:

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

• A $59 million decrease in operating costs from DENA’s continuing operations due primarily to the sale of the Southeast Plants in 2004 and the continued wind-down of DETM.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating expenses for the six months ended June 30, 2005 increased $839 million, compared to the same period in 2004. This change was driven primarily by:

• An approximate $900 million increase in operating expenses at Field Services and Natural Gas Transmission driven primarily by higher average NGL and natural gas prices, and foreign exchange impacts

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

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

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

Partially offsetting these increases in expenses were:

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

• A $118 million decrease in operating costs from DENA’s continuing operations due primarily to the sale of the Southeast Plants in 2004 and the continued wind-down of DETM.

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

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

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

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

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

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

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (losses) gains on sales of other assets, net for the six months ended June 30, 2005 increased $359 million, compared to the same period in 2004. The increase was due primarily to the charge in the first quarter 2004 associated with the sale of DENA’s Southeast Plants.

Consolidated Operating Income

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating income for the three months ended June 30, 2005 decreased $33 million, compared to the same period in 2004. Decreased operating income was due primarily to unfavorable results at Franchised Electric due primarily to milder weather and increased operating and maintenance expenses, the gain on sale of the Alexandria tract in the Washington D.C. area in the second quarter 2004, and an increase in liabilities associated with mutual insurance companies recorded in the second quarter 2005, partially offset by favorable results at Field Services driven primarily by favorable effects of commodity prices net of hedging.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated operating income for the six months ended June 30, 2005 increased $129 million, compared to the same period in 2004. Increased operating income was due primarily to a loss in 2004 related to the sale of DENA’s Southeast Plants, favorable results at Field Services driven primarily by favorable effects of commodity prices, net of hedging, favorable results from DENA’s continuing operations due primarily to the sale of the Southeast Plants in 2004, and favorable results at International Energy driven primarily by higher volumes and favorable foreign currency exchange rate changes, partially offset by charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, unfavorable results at Franchised Electric due primarily to increased operating and maintenance expenses and milder weather in 2005, and the gain on sale of the Alexandria tract in the Washington D.C. area in the second quarter 2004.

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

Consolidated Other Income and Expenses, net

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated other income and expenses, net for the three months ended June 30, 2005 decreased $13 million, compared to the same period in 2004. This decrease was due primarily to lower interest income and equity in earnings of unconsolidated affiliates, partially offset by gains on sales of equity investments in the second quarter 2005.

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

Consolidated Interest Expense

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated interest expense for the three months ended June 30, 2005 decreased $17 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated interest expense for the six months ended June 30, 2005 decreased $70 million, compared to the same period in 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004.

Consolidated Minority Interest Expense

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

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated minority interest expense for the six months ended June 30, 2005 increased $414 million, compared to the same period in 2004 driven primarily by increased earnings at DEFS as a result of the sale of TEPPCO GP and higher commodity prices.

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated income tax expense from continuing operations for the three months ended June 30, 2005 increased $15 million, compared to the same period in 2004. The increase primarily resulted from a release of various income tax reserves in the second quarter 2004, partially offset by lower income from continuing operations in 2005.

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated income tax expense from continuing operations for the six months ended June 30, 2005 increased $390 million, compared to the same period in 2004. The increase primarily resulted from higher earnings, primarily as a result of higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and the release of various income tax reserves in the second quarter 2004.

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

Three Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (loss) income from discontinued operations, net of tax for the three months ended June 30, 2005 decreased $45 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business and an unfavorable after-tax impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market gains associated with the disqualified hedge positions around the partially completed western plants in 2004, which were classified to discontinued operations as a result of the DENA exit plan, partially offset by an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Six Months Ended June 30, 2005 as Compared to June 30, 2004. Consolidated (loss) income from discontinued operations, net of tax for the six months ended June 30, 2005 decreased $186 million, compared to the same period in 2004. This decrease was driven primarily by an after-tax gain in 2004 related to the sale of the Asia-Pacific Business, partially offset by a favorable after-tax impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified to discontinued operations as a result of the DENA exit plan, and an after-tax charge recognized in the second quarter of 2004 on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

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Segment Results

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

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

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

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

EBIT by Business Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions)
Franchised Electric	$	274		$	338		$	610		$	762
Natural Gas Transmission		304			315			715			717
Field Services		165			92			1,083			180
DENA (a)		—			(57	)		—			(487	)
International Energy		86			68			154			97
Crescent		38			87			90			147
Total reportable segment EBIT		867			843			2,652			1,416
Other (a)		(118	)		(26	)		(320	)		(31	)
Interest expense		(295	)		(312	)		(585	)		(655	)
Interest income and other (b)		31			43			49			56
Consolidated earnings from continuing operations before income taxes	$	485		$	548		$	1,796		$	786

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

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

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

Franchised Electric

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

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

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

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

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

Operating Revenues. The increase was driven primarily by:

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

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

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

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

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

Operating Expenses. The increase was driven primarily by:

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

229

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

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

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

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

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

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

Operating Revenues. Operating revenues were consistent due primarily to:

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

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

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

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

Operating Expenses. The increase was driven primarily by:

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

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

• Increased regulatory amortization of $17 million, due primarily to increased amortization of compliance costs related to clean air legislation passed by North Carolina in 2002. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized by December 31, 2007. Regulatory amortization expenses were approximately $156 million for the six months ended June 30, 2005 as compared to $139 million during the same period in 2004, and

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

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

Matters Impacting Future Franchised Electric Results

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

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Natural Gas Transmission

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	764	$	703	$	61		$	1,955	$	1,756	$	199
Operating expenses		471		406		65			1,260		1,055		205
Gains on sales of other assets, net		1		9		(8	)		4		9		(5	)
Operating income		294		306		(12	)		699		710		(11	)
Other income, net of expenses		16		13		3			31		20		11
Minority interest expense		6		4		2			15		13		2
EBIT	$	304	$	315	$	(11	)	$	715	$	717	$	(2	)
Proportional throughput, TBtu (a)		719		726		(7	)		1,775		1,815		(40	)

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

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

Operating Revenues. The increase was driven primarily by:

• A $36 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• An $8 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas Limited (Union Gas). This revenue increase is offset in expenses, and

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

Operating Expenses. The increase was driven primarily by:

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

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

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

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

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

Operating Revenues. The increase was driven primarily by:

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

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

• A $10 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

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

Operating Expenses. The increase was driven primarily by:

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

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

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

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

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

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Field Services

	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Increase (Decrease)			2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,872	$	2,325	$	547		$	5,530	$	4,664	$	866
Operating expenses		2,637		2,200		437			5,210		4,417		793
Gains on sales of other assets, net		—		—		—			2		—		2
Operating income		235		125		110			322		247		75
Other income, net of expenses		7		17		(10	)		1,258		34		1,224
Minority interest expense		77		50		27			497		101		396
EBIT	$	165	$	92	$	73		$	1,083	$	180	$	903
Natural gas gathered and processed/transported, TBtu/d (a)		6.9		6.9		—			6.8		6.8		—
NGL production, MBbl/d (b)		365		360		5			362		352		10
Average natural gas price per MMBtu (c), (d), (e)	$	6.73	$	5.99	$	0.74		$	6.50	$	5.84	$	0.66
Average NGL price per gallon (d) (e)	$	0.75	$	0.61	$	0.14		$	0.74	$	0.60	$	0.14

(a) Trillion British thermal units per day

(b) Thousand barrels per day

(c) Million British thermal units

(d) Index-based market price

(e) Does not reflect results of commodity hedges.

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

Operating Revenues. The increase was driven primarily by:

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

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

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

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

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

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

Operating Expenses. The increase was due primarily to:

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

• A $15 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds, and for outside consulting fees

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

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

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

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

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

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

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

Operating Revenues. The increase was due primarily to:

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

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

232

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

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

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

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

• A $6 million increase attributable to higher transportation, storage and processing fees, primarily due to higher fees from processing contracts.

Operating Expenses. The increase was due primarily to:

• A $605 million increase due to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices

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

• A $30 million increase due to an increase in planned repairs and maintenance expenses for overhauls, pipeline integrity and turnarounds and for outside consulting fees

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

• A $10 million increase attributable to higher purchased raw natural gas supply.

Other Income, net of expenses. The increase was due primarily to:

• An approximate $1.1 billion pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Energy’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by

• A $16 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS due to commodity price increases. The overall increase was not proportionate to the increase in Field Services’ earnings during the six months ended June 30, 2005, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS’ results prior to the discontinuance of cash flow hedges during the first quarter of 2005, as discussed above.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and the favorable effects of commodity price increases. Also during the first three months of 2005, Duke Energy discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”). As a result of the discontinuance of hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the six months ended June 30, 2005.

Matters Impacting Future Field Services Results

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. The DEFS disposition transaction involves DEFS transferring its Canadian assets to Duke Energy’s Natural Gas Transmission business unit as well as Duke Energy receiving cash from ConocoPhillips. The DEFS disposition transaction is estimated to result in a pre-tax gain to Field Services of approximately $600 million. Duke Energy will deconsolidate its investment in DEFS in July 2005, subsequent to the closing of the DEFS disposition transaction. For further information see Duke Capital’s Current Report on Form 8-K dated July 11, 2005 which contains pro-forma information regarding the impact of the DEFS disposition transaction as if it occurred on January 1, 2004 for purposes of the pro-forma statement of operations and March 31, 2005 for the pro-forma balance sheet. Future Field Services results are subject to volatility for factors such as commodity price changes.

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DENA

	Three Months Ended June 30,								Six Months Ended June 30,
	2005		2004			Increase (Decrease)			2005		2004			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—	$	77		$	(77	)	$	—	$	94		$	(94	)
Operating expenses		—		124			(124	)		—		230			(230	)
(Losses) Gains on sales of other assets, net		—		(16	)		16			—		(369	)		369
Operating loss		—		(63	)		63			—		(505	)		505
Other income (loss), net of expenses		—		1			(1	)		—		1			(1	)
Minority interest benefit		—		(5	)		5			—		(17	)		17
EBIT	$	—	$	(57	)	$	57		$	—	$	(487	)	$	487
Actual plant production, GWh		—		1,528			(1,528	)		—		2,413			(2,413	)
Proportional megawatt capacity in operation										—		9,085			(9,085	)

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. DENA’s continuing operations for 2004 are included as a component of DENA’s segment earnings. The results of DENA’s discontinued operations for 2004 and 2005 are presented in Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in “Consolidated (Loss) Income from Discontinued Operations, net of tax” above.

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $81 million of power generation revenues, and

• ($4) million of other operating revenues, primarily driven by negative net trading margin at DETM.

Operating Expenses. The decrease was driven primarily by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $77 million of fuel costs

• $40 million of operations, maintenance and depreciation expenses

• $19 million of general and administrative expenses, and

• A ($13) million ($8 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Losses on Sales of Other Assets, net. The change was due to the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results were due primarily to pre-tax losses of approximately $16 million ($10 million net of minority interest benefit) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations.

Minority Interest Benefit. The decrease was driven by the inclusion of DENA’s 2005 results of continuing operations in Other. The minority interest benefit in the 2004 results of continuing operations was related to DETM.

EBIT. The increase was driven by the inclusion of DENA’s 2005 results of continuing operations in Other, as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $126 million of power generation revenues, and

• ($32) million of other operating revenues, primarily driven by negative net trading margin at DETM.

Operating Expenses. The decrease was driven primarily by the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results of DENA’s continuing operations include:

• $109 million of fuel costs

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• $93 million of operations, maintenance and depreciation expenses

• $41 million of general and administrative expenses, and

• A ($13) million ($8 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

Gains (Losses) on Sales of Other Assets, net. The change is due to the inclusion of DENA’s 2005 results of continuing operations in Other. The 2004 results were due primarily to pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants and $14 million ($8 million net of minority interest benefit) related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations.

Minority Interest Benefit. The decrease was driven by the inclusion of DENA’s 2005 results of continuing operations in Other. The minority interest benefit in the 2004 results of continuing operations was related to DETM.

EBIT. The increase was driven by the inclusion of DENA’s 2005 results of continuing operations in Other, as discussed above.

International Energy

	Three Months Ended June 30,						Six Months Ended June 30,
	2005		2004		Increase (Decrease)		2005		2004		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	182	$	147	$	35	$	350	$	301	$	49
Operating expenses		127		98		29		246		229		17
Operating income		55		49		6		104		72		32
Other income, net of expenses		34		22		12		55		31		24
Minority interest expense		3		3		—		5		6		(1	)
EBIT	$	86	$	68	$	18	$	154	$	97	$	57
Sales, GWh		4,527		4,247		280		9,062		8,811		251
Proportional megawatt capacity in operation								4,139		4,130		9

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $13 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $7 million increase in Guatemala mainly due to higher energy prices

• A $6 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices, and

• A $5 million increase in Argentina primarily due to higher volumes and higher prices.

Operating Expenses. The increase was driven primarily by:

• A $12 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• An $11 million increase in Guatemala mainly due to higher fuel prices, maintenance expense and a bad debt reversal in 2004, and

• An $8 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes.

Other Income, net of expenses. The increase was driven primarily by a $9 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by:

• A $14 million increase in El Salvador driven by higher energy prices and volumes as well as increased auxiliary services sales

• A $10 million increase in Brazil due to higher contracted and spot volumes as well as favorable exchange rates, partially offset by decreased prices

• A $10 million increase in Guatemala mainly due to higher energy prices, and

• A $7 million increase in Argentina due primarily to higher volumes and higher prices.

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Operating Expenses. The increase was driven primarily by:

• A $14 million increase in El Salvador due primarily to higher fuel prices and volumes as well as increased transmission costs

• A $13 million increase in Ecuador due to unplanned maintenance and higher fuel prices and volumes, partially offset by

• A $13 million decrease related to a 2004 charge for the planned disposition of the ownership share in Compãnia de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004.

Other Income, net of expenses. The increase was driven primarily by a $16 million increase in equity earnings from the National Methanol Company investment driven by higher product margins.

EBIT. The increase was due primarily to improved results in Brazil and higher equity earnings from National Methanol Company, partially offset by lower results in Central America and Ecuador and a $13 million charge associated with the planned disposition of the ownership share in Cantarell recorded in 2004.

Crescent

	Three Months Ended June 30,								Six Months Ended June 30,
	2005			2004		Increase (Decrease)			2005			2004		Increase (Decrease)
	(in millions)
Operating revenues	$	112		$	101	$	11		$	176		$	139	$	37
Operating expenses		79			75		4			130			111		19
Gains on sales of investments in commercial and multi-family real estate		12			62		(50	)		54			121		(67	)
Operating income		45			88		(43	)		100			149		(49	)
Other expense, net		(2	)		—		(2	)		(2	)		—		(2	)
Minority interest expense		5			1		4			8			2		6
EBIT	$	38		$	87	$	(49	)	$	90		$	147	$	(57	)

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was due primarily to a $14 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida offset by a $2 million decrease in residential club operations.

Operating Expenses. The increase was due primarily to a $7 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $2 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was due primarily to a $49 million decrease in real estate land sales resulting from large land sales in 2004 ($45 million gain from the sale of the Alexandria tract in the Washington, D.C. area in June of 2004) as compared to minimal land sales in the second quarter of 2005.

EBIT. The decrease was due primarily to the reduction in real estate land sales as discussed above.

Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The increase was driven primarily by a $42 million increase in residential developed lot sales, due to increased sales at The Rim project in Payson, Arizona, the Lake Keowee projects in northwestern South Carolina and the LandMar division in northeastern and central Florida.

Operating Expenses. The increase was driven primarily by a $24 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above offset by a $3 million decrease in commercial operating expense due to a smaller portfolio of commercial buildings in 2005.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by:

• A $49 million decrease in real estate land sales primarily due to the $45 million sale of the Alexandria tract in the Washington, D.C. area in June of 2004 as compared to minimal real estate land sales in the first half of 2005, and

• A $19 million decrease in commercial project sales due to the sale of a commercial project in the Washington, D.C. area in March of 2004 as compared to minimal project sales in the first half of 2005.

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EBIT. The decrease was due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in the first half of 2004 as compared to minimal project and real estate land sales in the first half of 2005, partially offset by an increase in residential developed lot sales.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, D.C. area which resulted in higher than normal gains during 2004. Crescent expects segment EBIT from continuing operations and discontinued operations in 2005 to be at, or above segment EBIT from continuing operations and discontinued operations of approximately $250 million in 2004. When property management or other significant continuing involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

Other

	Three Months Ended June 30,									Six Months Ended June 30,
	2005			2004			Increase (Decrease)			2005			2004			Increase (Decrease)
	(in millions)
Operating revenues	$	181		$	290		$	(109	)	$	228		$	634		$	(406	)
Operating expenses		304			311			(7	)		560			698			(138	)
(Loss) Gains on sales of other assets, net		—			(7	)		7			3			7			(4	)
Operating loss		(123	)		(28	)		(95	)		(329	)		(57	)		(272	)
Other income, net of expenses		2			2			—			5			26			(21	)
Minority interest benefit		(3	)		—			(3	)		(4	)		—			(4	)
EBIT	$	(118	)	$	(26	)	$	(92	)	$	(320	)	$	(31	)	$	(289	)

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to the assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Other beginning in 2005. Prior to 2005, DENA’s continuing operations are included as a component of the DENA segment. The inclusion of DENA’s continuing operations for the three months ended June 30, 2005 increased Other’s segment losses by approximately $30 million. For the six months ended June 30, 2005, the inclusion of DENA’s continuing operations increased Other’s segment losses by approximately $60 million.

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $131 million decrease in revenue as a result of the continued wind-down of DEM, and

• An approximate $20 million decrease as a result of the mark-to-market impact of certain cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were discontinued and transferred to Other (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”), partially offset by

• A $33 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s revenues from continuing operations consist primarily of power generation revenues from the Midwestern assets.

Operating Expenses. The decrease was driven primarily by:

• A $131 million decrease as a result of the continued wind-down of DEM, partially offset by

• A $65 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s expenses from continuing operations consist of $30 million of fuel costs, $13 million of general and administrative expenses, and $22 million of operations, maintenance and depreciation expenses.

• A $24 million charge to increase liabilities associated with mutual insurance companies, and

• A $21 million reduction in operating expenses in 2004 at DEM, as a result of a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

(Loss) Gains on Sales of Other Assets, net. Gains on sales of other assets for the three months ended June 30, 2005 changed primarily due to a $7 million loss on the sale of an aircraft in 2004.

EBIT. The decrease was due primarily to the movement of DENA’s continuing operations to Other in 2005, the mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, an increase in liabilities associated with mutual insurance companies and the 2004 gain related to the settlement of the Enron bankruptcy proceedings, as discussed above.

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Six Months Ended June 30, 2005 as Compared to June 30, 2004

Operating Revenues. The decrease was driven primarily by:

• A $328 million decrease in revenues as a result of the continued wind-down of DEM, and

• An approximate $130 million decrease as a result of the mark-to-market impact of certain cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were discontinued and transferred to Other (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”), partially offset by

• A $42 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s revenues from continuing operations consist primarily of power generation revenues from the Midwestern assets.

Operating Expenses. The decrease was driven primarily by:

• A $332 million decrease as a result of the continued wind-down of DEM, partially offset by

• A $112 million increase as a result of the movement of DENA’s continuing operations to Other in 2005. DENA’s expenses from continuing operations consist of $40 million of fuel costs, $29 million of general and administrative expenses, and $43 million of operations, maintenance and depreciation expenses.

• An approximate $50 million charge to increase liabilities associated with mutual insurance companies, and

• A $21 million reduction in operating expenses in 2004 at DEM as a result of a gain related to the settlement of the Enron bankruptcy proceedings in April 2004.

(Losses) Gains on Sales of Other Assets, net. The decrease was driven primarily by:

• A $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad) in 2004, partially offset by

• A $7 million loss on the sale of an aircraft in 2004.

Other Income, net of expenses. The decrease was driven primarily by:

• A $17 million decrease in equity earnings from Duke/Fluor Daniel (D/FD) as a result of the wind-down of the partnership, and

• A $10 million decrease in earnings from executive life insurance.

EBIT. The decrease was due primarily to the mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the movement of DENA’s continuing operations to Other in 2005, an increase in liabilities associated with mutual insurance companies, the 2004 gain related to the settlement of the Enron bankruptcy proceedings, and the decrease in equity earnings from D/FD, as discussed above.

Matters Impacting Future Other Results

Future Other results will be subject to volatility as a result of the changes in the mark-to-market of certain Field Services commodity price risk contracts subsequent to the discontinuance of hedge accounting in first quarter 2005. The fair value of these contracts as of June 30, 2005 was a liability of approximately $225 million, and approximately $120 million of this value is attributable to contracts which will settle in 2005. As these contracts settle Duke Energy will realize an offset to revenues at Field Services.

Other Impacts on Earnings Available for Common Stockholders

Three Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $17 million, due primarily to Duke Energy’s debt reduction efforts in 2004.

Minority Interest Expense. Minority interest expense increased by $34 million driven primarily by increased earnings from DEFS, as a result of higher commodity prices.

Income Tax Expense from Continuing Operations. The effective tax rate for the three months ended June 30, 2005 was 32%, compared to 26% for the same period in 2004. The increase in the effective tax rate was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004. The impact of this prior-year release of income tax reserves was offset by lower pretax earnings during the three months ended June 30, 2005, compared to the same period in 2004.

(Loss) Income from Discontinued Operations, net of tax. The $45 million decrease was driven primarily by a $40 million after-tax gain in the second quarter of 2004 related to the sale of the Asia-Pacific Business and an $18 million after-tax unfavorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market gains associated with the disqualified hedge positions around the partially completed western plants in 2004, which were classified to discontinued operations as a result of the DENA exit plan, partially offset by a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

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Six Months Ended June 30, 2005 as Compared to June 30, 2004

Interest Expense. Interest expense decreased $70 million, due primarily to Duke Energy’s debt reduction efforts in 2004.

Minority Interest Expense. Minority interest expense increased $414 million, driven primarily by increased earnings at DEFS, as a result of the sale of TEPPCO GP and higher commodity prices.

Income Tax Expense from Continuing Operations. The effective tax rate for the six months ended June 30, 2005 was 34%, compared to 28% for same period in 2004. The increase was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in the second quarter of 2004. Additionally, the increase in income tax expense from continuing operations is a result of higher pretax earnings, due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, as discussed above.

(Loss) Income from Discontinued Operations, net of tax. The $186 million decrease was driven primarily by a $278 million after-tax gain recorded in 2004 related to the sale of International Energy’s Asia-Pacific Business, partially offset by an $86 million after-tax favorable impact from DENA’s discontinued operations resulting primarily from the absence of mark-to-market losses associated with the disqualified hedge positions around the partially completed western plants in 2004 and a gain recorded in 2005 associated with the sale of the partially completed Grays Harbor power plant in Washington state, which were classified to discontinued operations as a result of the DENA exit plan, and a $9 million after-tax charge on the note receivable from Norsk Hydro ASA related to International Energy’s sale of its European Business recognized in the second quarter of 2004 (see Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $377 million for the six months ended June 30, 2005, compared to the same period in 2004 due to approximately $300 million of additional collateral posted by Duke Energy during 2005 attributable to increased crude oil prices, as well as increases to the forward market prices of power, offset by approximately $100 million of additional collateral posted by Duke Energy in 2004, and a tax refund received in 2004 due to a taxable loss in 2003. These decreases in cash provided by operating activities were partially offset by an increase in cash collected from receivables at DENA and DEFS in 2005.

Investing Cash Flows

Net cash provided by (used in) investing activities increased approximately $1.7 billion for the six months ended June 30, 2005 as compared to the same period in 2004. This increase was principally driven by the approximate $1.3 billion in proceeds on sales of equity investments and other assets in 2005, primarily due to the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP for approximately $1.2 billion, offset by the approximate $700 million in proceeds received in 2004 primarily as a result of the sale of the Asia-Pacific business, the sale of turbines and excess equipment, and the sale of Field Services’ assets. Additionally, approximately $70 million of the increase in investing activities is due to reduced capital and investment expenditures during 2005. Additionally, during 2004, an additional amount of cash of approximately $1 billion was invested in short-term investments as a result of the 2004 disposition transactions and increased operating cash flows, as discussed above, which resulted in excess cash balances being invested in these short-term investments.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased approximately $1.5 billion for the six months ended June 30, 2005, compared to same period in 2004. This change was due primarily to the 2005 repurchase of 32.6 million shares of common stock for $909 million, including approximately $10 million in commissions and other fees (see Note 3 to the Consolidated Financial Statements, “Common Stock”), and lower proceeds from common stock issuances during 2005 driven by the $875 million settlement of the forward purchase contract component of Duke Energy’s Equity Units in 2004. This was partially offset by approximately $340 million of higher redemptions and net paydowns of long-term debt, commercial paper, notes payable, and preferred stock of a subsidiary during 2004.

Cash generated from operations, the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, and the DEFS disposition transaction are expected to be adequate for funding Duke Energy’s capital expenditures, dividend payments and share repurchases for 2005.

With cash, cash equivalents and short-term investments on hand of approximately $2.0 billion as of June 30, 2005, along with a more stable business environment, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy continues to evaluate these options to determine the best economic decision to meet the needs of shareholders and the long-term financial strength of Duke Energy.

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Significant Financing Activities. In December 2004, Duke Energy reached an agreement to sell its Grays Harbor facility to an affiliate of Invenergy LLC. In 2004, Duke Energy terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

During the first quarter of 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

In connection with the up to $2.5 billion share repurchase program announced in February 2005, Duke Energy entered into an accelerated share repurchase transaction. Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share (see Note 3 to the Consolidated Financial Statements, “Common Stock”). Duke Energy also entered into a separate open-market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of June 30, 2005, Duke Energy had repurchased 2.6 million shares of its common stock through the separate open-market purchase plan at a weighted average price of $28.97 per share. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment.

On June 29, 2005, Duke Energy declared a quarterly cash dividend on its common stock of $0.31 per share, an increase of $0.035 cents per share above its previous level. The dividend is payable on September 16, 2005, to shareholders of record at the close of business on August 12, 2005.

Available Credit Facilities and Restrictive Debt Covenants. Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.

Credit Ratings. The credit ratings of Duke Energy, Duke Capital and its subsidiaries, with the exception of Maritimes & Northeast Pipeline LLC and Maritimes & Northeast LP, have not changed since March 1, 2005 as disclosed in “Management’s Discussion and Analysis of Results of Operations and Financial Condition – Liquidity and Capital Resources” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. The following table summarizes the August 5, 2005 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

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Credit Ratings Summary as of August 5, 2005

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy (a)	BBB	Baa1	Not applicable
Duke Capital LLC (a)	BBB-	Baa3	Not applicable
Duke Energy Field Services (a)	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP (a)	BBB	Baa2	Not applicable
Westcoast Energy Inc.	BBB	Not applicable	A(low)
Union Gas Limited (a)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC (b)	A	A2	A
Maritimes & Northeast Pipeline, LP (b)	A	A2	A
Duke Energy Trading and Marketing, LLC (c)	BBB-	Not applicable	Not applicable

(a) Represents senior unsecured credit rating

(b) Represents senior secured credit rating

(c) Represents corporate credit rating

In May 2005, following the announcement of Duke Energy’s merger with Cinergy, Standard & Poor’s Ratings Service placed the ratings of Duke Energy and its subsidiaries (excluding DEFS, Maritimes & Northeast Pipeline LLC and Maritimes & Northeast Pipeline LP) on “CreditWatch with negative implications.” In addition, Moody’s Investors Service revised the ratings outlook of Duke Energy, Duke Capital and Texas Eastern Transmission LP to “Developing” and Dominion Bond Rating Service placed the credit ratings of Westcoast Energy Inc. “Under Review with Developing Implications.”

In August 2005, Moody’s Investors Service downgraded the credit rating of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP from A1 to A2. Moody’s actions were primarily a result of their concerns over downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. Moody’s concluded their action placing the ratings outlook for both companies to “stable”.

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted. In addition, the completion of the merger with Cinergy and the resulting corporate structure could impact the credit ratings of Duke Energy or its subsidiaries.

Duke Energy and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Energy’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Energy’s collateral requirements. DENA conducts business throughout the United States and Canada through Duke Energy North America LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participates in DETM, which is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy.

A reduction in DETM’s credit rating to below investment grade as of June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $150 million. Additionally, as a result of DETM’s credit rating as of June 30, 2005, Duke Capital could be required to segregate up to approximately $260 million of cash collateral held by Duke Capital. Amounts above reflect Duke Energy’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of June 30, 2005 would have resulted in Duke Capital posting additional collateral of approximately $290 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate swap and foreign exchange agreements may require

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settlement payments due to termination of the agreements. As of June 30, 2005, Duke Capital could have been required to pay up to $10 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.

If credit ratings for Duke Energy or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to quantify fully in addition to the posting of additional collateral and segregation of cash described above.

Other Financing Matters. As of June 30, 2005, Duke Energy and its subsidiaries had effective Securities and Exchange Commission (SEC) shelf registrations for up to $1,542 million in gross proceeds from debt and other securities. The total amount available under effective shelf registrations decreased $500 million as compared to December 31, 2004, resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of June 30, 2005, Duke Energy had access to 900 million Canadian dollars (approximately U.S. $732 million) available under the Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 500 million Canadian dollars will expire in November 2005 and 400 million Canadian dollars will expire in July 2006.

Off-Balance Sheet Arrangements

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction for 30 million shares as part of its publicly announced share repurchase program that allows Duke Energy to purchase up to $2.5 billion of its common stock over the next three years. In connection with this transaction, Duke Energy simultaneously entered into a forward sale contract with an investment bank that is indexed to and potentially settled in its own common stock. The forward sale contract is a derivative instrument and is classified as equity and is therefore considered to be an off-balance sheet arrangement (see Note 3 to the Consolidated Financial Statements, “Common Stock”). For additional information on Duke Energy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004.

Contractual Obligations and Commercial Commitments

Duke Energy enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the first six months of 2005, there were no material changes in Duke Energy’s contractual obligations and commercial commitments. For an in-depth discussion of Duke Energy’s contractual obligations and commercial commitments, see “Contractual Obligations and Commercial Commitments” and “Quantitative and Qualitative Disclosures about Market Risk” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004.

OTHER ISSUES

Merger with Cinergy. On May 9, 2005, Duke Energy and Cinergy announced they have entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at June 30, 2005, the holding company would issue approximately 310 million shares to consummate the merger. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction would be valued at approximately $9 billion and would result in incremental goodwill to Duke Energy of approximately $4 billion. The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated in the first half of 2006. Completion of the merger is subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. (For further discussion of the status of regulatory filings see Note 14 to the Consolidated Financial Statements, “Regulatory Matters”.) The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

Although Duke Energy and Cinergy believe that the expectation as to timing for the closing of the merger described above is reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all required approvals will be received.

Further information concerning the structure and details of the proposed merger is set forth in Duke Energy’s Current Report on Form 8-K dated May 9, 2005, which includes as exhibits the merger agreement and a joint press release of Duke Energy and Cinergy announcing the execution of the merger agreement. In connection with the merger, a registration statement on Form S-4 has been filed with the SEC by Duke Energy Holding Corp. (Registration No. 333-126318), containing a preliminary joint proxy statement/prospectus.

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Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Energy has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6% below their 1990 level over the period 2008 to 2012. The Canadian government’s strategy for achieving its Kyoto reduction target includes, among other things, a proposal for an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (LFE). Consultations to develop plan details for the LFE program are under way. A draft LFE rule could be issued in the fall of 2005 and finalized in the spring of 2006. If an LFE program is ultimately enacted, then all of Duke Energy’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of carbon dioxide (CO₂) emission credits to actual emission reductions at the source, or a combination of strategies.

In 2001, President George W. Bush declared that the United States would not ratify the Kyoto Protocol. Instead, the U.S. greenhouse gas policy currently favors voluntary actions, continued research, and technology development over near-term mandatory greenhouse gas reduction requirements. Although several bills have been introduced in Congress that would compel CO₂ emission reductions, none has advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO₂ emission reduction program being enacted in the near future, or the specific requirements of any such regime, is highly uncertain. Some states are contemplating or have taken steps to manage greenhouse gas emissions, and while a number of U.S. states in the Northeast and far West are discussing the possibility of enacting either state-specific or regional programs in the future that would mandate reductions in greenhouse gas emissions, the outcome of those discussions is highly uncertain.

Duke Energy recently announced that it supports the enactment of U.S. federal legislation that would encourage a gradual transition to a lower-carbon-intensive economy, preferably in the form of a federal-level carbon tax that would apply to all sectors of the economy. Duke Energy believes that it is in the best interest of its investors and customers to actively participate in the evolution of federal policy on this important issue.

That Duke Energy will be proactive in climate change policy debate in the United States does not change the uncertainty around climate change policy. Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian policy, Duke Energy cannot estimate the potential effect of either nation’s greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Energy will assess and respond to the potential implications of greenhouse gas policies for its business operations in the United States and Canada if policies become sufficiently developed and certain to support a meaningful assessment.

(For additional information on other issues related to Duke Energy, see Note 14 to the Consolidated Financial Statements, “Regulatory Matters” and Note 15 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of June 30, 2005:

Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), “Share-Based Payment”. In December of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes Accounting Principles Board (APB) Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Timing for implementation of SFAS No. 123R, as amended in April 2005 by the SEC, is no later than the beginning of the first annual period beginning after June 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. Under SFAS No. 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period restated.

Duke Energy currently has retirement eligible employees with outstanding share-based payment awards. Compensation cost related to those awards is currently recognized over the stated vesting period or until actual retirement occurs. Upon adoption of SFAS No. 123R, Duke Energy will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

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The impact on Earnings Per Share (EPS) for the three and six month periods ended June 30, 2005 and 2004 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed in the Pro Forma Stock-Based Compensation table included in Note 4 to the Consolidated Financial Statements, “Stock-Based Compensation”. Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. Duke Energy does not anticipate the adoption of SFAS No. 123R, which is currently planned for January 1, 2006, will have any material impact on its consolidated results of operations, cash flows or financial position. The impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment”. On March 29, 2005, the SEC staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy is currently in the process of implementing SFAS No. 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29”. In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. SFAS No. 153 does not apply to transfers of nonmonetary assets between entities under common control. The impact to Duke Energy of adopting SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Energy does not currently expect adoption of SFAS No. 153 will have a material impact on its consolidated results of operations, cash flows or financial position.

FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations”. In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. Duke Energy is currently evaluating the impact of adopting FIN 47 as well as the interim transition provisions and cannot currently estimate the impact of FIN 47 on its consolidated results of operations, cash flows or financial position.

Subsequent Events

Subsequent events have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-Q for the quarter ended June 30, 2005, except for the following sections discussed below:

• Acquisitions and Dispositions – Field Services

• Acquisitions and Dispositions – DENA

Acquisitions and Dispositions - Field Services. In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP) for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion and Minority Interest Expense of $343 million to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. During 2005, Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $.8 billion in cash and approximately $.3 billion of assets. The DEFS disposition resulted in pre-tax gain of approximately $575 million in third quarter 2005. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. In connection with the DEFS disposition, Duke Energy acquired ConocoPhillips interest in the Empress System gas processing and natural gas liquids marketing business (Empress System) in August 2005 for cash of approximately $230 million.

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Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The DEFS Canadian natural gas gathering and processing facilities and the Empress System are included in Natural Gas Transmission (see also Note 9 to the Consolidated Financial Statements).

As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market. As a result, approximately $355 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy in the nine months ended September 30, 2005. Upon the discontinuance of hedge accounting, approximately $120 million of pre-tax charges were recognized while approximately $235 million of losses have been recognized subsequent to discontinuance of hedge accounting.

Acquisitions and Dispositions - DENA. As described in Note 11 to the Consolidated Financial Statements, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. In connection with this exit plan, Duke Energy recognized a non-cash, net pre-tax charge of approximately $1.3 billion in the third quarter of 2005. The charge relates to:

• The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)

• The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan, and

• Pre-tax impairments of approximately $0.6 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon information from third party valuations and internal valuations.

In addition to these amounts, at September 30, 2005, approximately $150 million of pre-tax deferred net gains remain in AOCI related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings over the next 12 months as the forecasted transactions occur. In addition, management anticipates that additional charges will be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts estimated at approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs. The actual amount of future additional charges related to the DENA exit plan will vary depending on changes in market conditions and other factors, and could differ from management’s current expectation.

DENA may also realize future potential gains on sales of certain plants which will be recognized when sold. Subsequent to September 30, 2005, DENA has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. Included in the estimated exit costs are the effects of DENA’s November 17, 2005 agreement to sell to Barclays Bank PLC (Barclays) substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and contracts related to DENA’s energy marketing and management activities. Excluded from the sale to Barclays are commodity contracts associated with the near-term value of DENA’s west and northeastern generation assets and with remaining gas transportation and structured power contracts. Among other things, the agreement provides that effective November 17, 2005 all economic benefits and burdens under the contracts were transferred to Barclays. DENA agreed to pay Barclays cash consideration of approximately $700 million by January 3, 2006 and as the contracts are novated, assigned or terminated, all net collateral posted by DENA under those contracts will be returned to DENA. Net cash collateral to be returned to DENA is expected to substantially offset the cash consideration to be paid to Barclays. The novation or assignment of physical power contracts is subject to Federal Energy Regulatory Commission approval.

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As of September 30, 2005, DENA’s assets and liabilities to be disposed of under the exit plan, were classified as Assets Held for Sale and consisted of the following:

Summarized DENA Assets and Associated Liabilities Held for Sale As of September 30, 2005 (in millions)

Current assets	$	1,579
Investments and other assets		1,556
Net property, plant and equipment		1,151
Total assets held for sale	$	4,286
Current liabilities	$	1,605
Long-term debt and other deferred credits		2,260
Total liabilities associated with assets held for sale	$	3,865

In October 2005, the Ft. Frances generation facility was sold to a third party for proceeds which approximate the carrying value of the sold assets.

Regulatory Matters – Other. The Energy Policy Act of 2005 became law in August 2005 and addresses a wide span of issues. The legislation directs specified agencies to conduct a significant number of studies on various sectors of the energy industry. In addition, many of the provisions will require these agencies to develop rules and procedures for their application. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA), establishes a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear plants, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission, improves the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. The enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 9.

For information on subsequent events related to acquisitions and dispositions, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and income taxes, see Notes 9, 11, 14, 15 and 18.

Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk.

For an in-depth discussion of Duke Energy’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004.

Commodity Price Risk

Normal Purchases and Normal Sales. The unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption was approximately $1.4 billion as of June 30, 2005 and $900 million as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized net gains on natural gas and power cash flow hedge positions of approximately $1.2 billion as June 30, 2005 and $750 million as of December 31, 2004, which are recorded on the Consolidated Balance Sheets in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. A key objective for Duke Energy in 2005 is to position DENA to be a successful merchant operator. Duke Energy is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. Depending on the options selected, there is a risk that material impairments or other charges or credits could be recorded, including the potential disqualification of DENA’s power forward sales contracts designated under the normal purchases and normal sales exemption. This would result in the recognition of all unrealized losses associated with these forward contracts. These amounts exclude obligations attributable to DENA’s gas transportation and structured power portfolio. For further information, see Item 7 “Contractual Obligations” disclosure in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2004. The timing of recognition of any loss on the normal purchases and normal sales contracts and the recognition of any unrealized net gains on DENA cash flow hedge positions may or may not occur in the same period, depending upon the options selected. See Note 11 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for more information regarding DENA’s exit plan.

Trading and Undesignated Contracts. The risk in the mark-to-market portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Energy’s DER amounts for commodity derivatives recorded using the mark-to-market model of accounting are shown in the following table.

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Daily Earnings at Risk (in millions)

	June 30, 2005 One- Day Impact on Operating Income for 2005 (a)		Estimated Average One- Day Impact on Operating Income for Second Quarter 2005 (a)		Estimated Average One- Day Impact on Operating Income for the Year 2004 (a)		High One- Day Impact on Operating Income for Second Quarter 2005 (a)		Low One- Day Impact on Operating Income for Second Quarter 2005 (a)
Calculated DER	$	3	$	4	$	16	$	6	$	3

(a) DER measures the mark-to-market portfolio’s impact on earnings. While this calculation includes both trading and undesignated contracts, the trading portion, as defined by EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” is not material.

The DER figures above do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips (see Note 13 to the Consolidated Financial Statements, “Risk Management Instruments”).

Credit Risk

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments due to IDC. In 2000, Duke Hidalgo was sold to Calpine Corporation and Duke Capital remained responsible for the lease guaranty obligations. Calpine Corporation has indemnified Duke Capital’s lease guaranty obligations. Total maximum exposure under this guarantee obligation as of June 30, 2005 is approximately $200 million.

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EX-99.4

Exhibit 99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-103515, 333-81940, 333-85486, and 333-115216 of Duke Energy Corporation on Form S-3, and Registration Statement Nos. 333-29563, 333-12093, 333-50317, 333-59279, and 333-84222 of Duke Energy Corporation on Form S-8, of our report dated March 16, 2005 (December 9, 2005 as to the references to the Duke Energy North America discontinued operations and the segment changes in the “Reclassifications and Other Changes” section of Note 1, and the reference to “Acquisitions and Dispositions-Cinergy Merger” in Note 23) relating to the financial statements and financial statement schedule of Duke Energy Corporation (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the adoption of new accounting pronouncements and an explanatory paragraph regarding the agreements in February 2005 to sell Texas Eastern Products Pipeline Company LLC to Enterprise GP Holdings L.P. and to transfer a 19.7% interest in Duke Energy Field Services to ConocoPhillips), and to our report dated March 16, 2005 relating to management’s report on the effectiveness of internal control over financial reporting, appearing in this Current Report on Form 8-K of Duke Energy Corporation dated December 9, 2005.

DELOITTE & TOUCHE LLP

Charlotte, North Carolina

December 9, 2005