Spectra Energy Capital 10-Q 2003 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended June 30, 2003

Commission File Number 0-23977

DUKE CAPITAL CORPORATION

(Exact name of Registrant as Specified in its Charter)

Delaware	51-0282142
(State or Other Jurisdiction of Incorporation)	(IRS Employer Identification No.)

526 South Church Street Charlotte, NC 28202-1904

(Address of Principal Executive Offices)

(Zip code)

704-594-6200

(Registrant’s telephone number, including area code)

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

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

All of the Registrant’s common shares are directly owned by Duke Energy Corporation (File No. 1-4928), which files reports and proxy materials pursuant to the Securities Exchange Act of 1934.

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

Number of shares of Common Stock, without par value, outstanding at July 31, 2003.....1,010

DUKE CAPITAL CORPORATION

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2003

INDEX

Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements	1
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2003 and 2002	1
	Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002	2
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002	4
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2003 and 2002	5
	Notes to Consolidated Financial Statements	6
2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	30
3.	Quantitative and Qualitative Disclosures about Market Risk	47
4.	Controls and Procedures	48
	PART II. OTHER INFORMATION
1.	Legal Proceedings	49
6.	Exhibits and Reports on Form 8-K	49
	Signatures	50

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

Duke Capital 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 the Company’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 the Company’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 the Company’s service territories

• The weather and other natural phenomena

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

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

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

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

• Lack of improvement or further declines in the market prices of equity securities and resultant cash funding requirements for the Company’s defined benefit pension plans

• The level of creditworthiness of counterparties to the Company’s transactions

• The amount of collateral required to be posted from time to time in the Company’s transactions

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

• 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 and

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

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 the Company has described. The Company 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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PART I. FINANCIAL INFORMATION

Item  1. Financial Statements.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003			2002
Operating Revenues
Sales of natural gas and petroleum products	$	2,479	$	1,413	$	5,883		$	2,422
Transportation and storage of natural gas		415		447		832			773
Electric generation		420		470		938			964
Other		446		69		531			448
Total operating revenues		3,760		2,399		8,184			4,607
Operating Expenses
Natural gas and petroleum products purchased		2,223		994		5,085			1,901
Fuel used in electric generation and purchased power		117		131		377			275
Other operation and maintenance		614		490		1,024			1,044
Depreciation and amortization		274		238		541			426
Property and other taxes		69		63		137			124
Total operating expenses		3,297		1,916		7,164			3,770
Gains on Sales of Other Assets, net		26		16		27			1
Operating Income		489		499		1,047			838
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		17		100		51			109
Gains on sale of equity investments		219		—		233			14
Other income and expenses, net		40		32		63			88
Total other income and expenses		276		132		347			211
Interest Expense		272		217		550			357
Minority Interest Expense		49		52		90			73
Earnings Before Income Taxes		444		362		754			619
Income Taxes		147		123		250			206
Income Before Cumulative Effect of Change in Accounting Principles		297		239		504			413
Cumulative Effect of Change in Accounting Principles, net of tax		—		—		(52	)		—
Net Income	$	297	$	239	$	452		$	413

See Notes to Consolidated Financial Statements.

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	June 30, 2003		December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	1,452	$	814
Receivables		5,403		6,549
Inventory		664		666
Unrealized gains on mark-to-market and hedging transactions		2,476		2,013
Other		855		717
Total current assets		10,850		10,759
Investments and Other Assets
Investments in unconsolidated affiliates		1,625		2,074
Goodwill, net of accumulated amortization		3,747		3,747
Notes receivable		535		589
Unrealized gains on mark-to-market and hedging transactions		3,037		2,173
Other		2,204		2,156
Total investments and other assets		11,148		10,739
Property, Plant and Equipment
Cost		30,872		29,238
Less accumulated depreciation and amortization		4,394		4,026
Net property, plant and equipment		26,478		25,212
Regulatory Assets and Deferred Debits		971		855
Total Assets	$	49,447	$	47,565

See Notes to Consolidated Financial Statements.

2

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	June 30, 2003		December 31, 2002
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	5,012	$	5,647
Notes payable and commercial paper		414		683
Taxes accrued		390		—
Interest accrued		251		236
Current maturities of long-term debt		852		1,148
Unrealized losses on mark-to-market and hedging transactions		1,970		1,744
Other		1,322		1,538
Total current liabilities		10,211		10,996
Long-term Debt		15,612		15,703
Deferred Credits and Other Liabilities
Deferred income taxes		3,629		3,222
Unrealized losses on mark-to-market and hedging transactions		2,085		1,439
Other		1,421		1,395
Total deferred credits and other liabilities		7,135		6,056
Commitments and Contingencies
Guaranteed Preferred Beneficial Interests in SubordinatedNotes of Duke Capital Corporation		583		825
Minority Interests		1,884		1,904
Common Stockholder’s Equity
Common stock, no par, 3,000 shares authorized, 1,010 shares outstanding		—		—
Paid-in capital		8,332		7,545
Retained Earnings		5,196		4,748
Accumulated other comprehensive income (loss)		494		(212	)
Total common stockholder's equity		14,022		12,081
Total Liabilities and Stockholder’s Equity	$	49,447	$	47,565

See Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	452		$	413
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		541			426
Cumulative effect of change in accounting principle		52			—
Gains on sales of equity investments and other assets		(260	)		—
Deferred income taxes		56			24
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(110	)		93
Receivables		978			352
Inventory		(8	)		41
Other current assets		(127	)		(209	)
Increase (decrease) in
Accounts payable		(652	)		570
Taxes accrued		377			331
Interest accrued		15			5
Other current liabilities		(81	)		(335	)
Other, assets		(42	)		(74	)
Other, liabilities		42			(385	)
Net cash provided by operating activities		1,233			1,252
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net		(933	)		(2,712	)
Acquisition of Westcoast Energy Inc., net of cash acquired		—			(1,707	)
Proceeds from the sale equity investments and other assets and collections on notes receivable		1,196			203
Other		(10	)		298
Net cash provided by (used in) investing activities		253			(3,918	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		259			1,507
Payments for the redemption of long-term debt		(827	)		(523	)
Payments for the redemption of guaranteed preferred beneficial interests in subordinated notes		(250	)		—
Net change in notes payable and commercial paper		(802	)		676
Contributions from minority interests		1,467			1,624
Distributions to minority interests		(1,484	)		(1,363	)
Capital contributions from parent		800			500
Dividends paid		(7	)		—
Other		(4	)		36
Net cash (used in) provided by financing activities		(848	)		2,457
Net increase (decrease) in cash and cash equivalents		638			(209	)
Cash and cash equivalents at beginning of period		814			263
Cash and cash equivalents at end of period	$	1,452		$	54

See Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Net Income	$	297		$	239		$	452		$	413
Other comprehensive income (loss):
Foreign currency translation adjustments		240			(102	)		404			(126	)
Net unrealized gains (losses) on cash flow hedges		420			(83	)		689			371
Reclassification of (gains) losses from cash flow hedges into earnings		(112	)		28			(202	)		(188	)
Other comprehensive income (loss), before income taxes		548			(157	)		891			57
Income tax (expense) benefit related to items of other comprehensive income		(128	)		7			(185	)		(68	)
Total other comprehensive income (loss)		420			(150	)		706			(11	)
Total Comprehensive Income	$	717		$	89		$	1,158		$	402

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Duke Capital Corporation (collectively with its subsidiaries, the Company) is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as the parent of certain of Duke Energy’s non-utility and other operations. The Company provides financing and credit enhancement services for its subsidiaries and conducts its operations through the business segments described below.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., and in Canada. Natural Gas Transmission also provides gas sales and distribution service to retail customers in Ontario and Western Canada, and gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. Duke Energy Gas Transmission’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commissio’s (FERC’s), the Texas Railroad Commission’s, and the Department of Transportation’s rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are subject to the rules and regulations of the National Energy Board, the Ontario Energy Board and the British Columbia Utilities Commission.

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and produces, transports, trades and markets, and stores natural gas liquids. It conducts operations primarily through Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by the Company. Field Services gathers natural gas from production wellheads in Western Canada and 11 contiguous states in the U.S. Those systems serve major natural gas-producing regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well as onshore and offshore Gulf Coast areas.

Duke Energy North America (DENA) develops, operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is approximately 40% owned by ExxonMobil Corporation and approximately 60% owned by the Company. On April 11, 2003, the Company announced that it is exiting proprietary trading at DENA.

International Energy develops, operates and manages natural gas transportation and power generation facilities, and engages in sales and marketing of natural gas and electric power outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC and its activities target power generation in Latin America, power generation and natural gas transmission in Asia-Pacific, and natural gas marketing in Northwest Europe. International Energy initiated exiting proprietary trading during the quarter ended June 30, 2003.

Beginning in 2003, the business segments formerly known as Other Energy Services and Duke Ventures were combined and have been presented as Other Operations. Other Operations is composed of diverse businesses, operating through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet), Duke Capital Partners, LLC (DCP), Duke/Fluor Daniel (D/FD) and Energy Delivery Services (EDS). Crescent develops high-quality commercial, residential and multi-family real estate projects and manages land holdings primarily in the Southeastern and Southwestern U.S. DukeNet develops and manages fiber optic communications systems for wireless, local and long-distance communications companies; and for selected educational, governmental, financial and health care entities. DCP, a wholly owned merchant finance company, provides debt and equity capital and financial advisory services primarily to the energy industry. In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner. D/FD provides comprehensive engineering, procurement,

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construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD is a 50/50 partnership between the Company and a subsidiary of Fluor Corporation. On July 9, 2003, the Company and Fluor Corporation announced that the partnership between subsidiaries of the two companies will be dissolved, at the request of Fluor Corporation. The partners of D/FD have adopted a plan for an orderly wind-down of the business of D/FD over the next two years. EDS is an engineering, construction, maintenance and technical services firm specializing in electric transmission and distribution lines and substation projects.

2. Summary of Significant Accounting Policies

Consolidation. The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating intercompany transactions and balances. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the interim Consolidated Statements of Income 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 and other factors.

Conformity with generally accepted accounting principles (GAAP) in the U.S. requires management to make 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 of current and expected future events, actual results could be different from those estimates.

Inventory. Inventory consists primarily of materials and supplies, and natural gas and natural gas liquid products held in storage for transmission, processing and sales commitments. This inventory is recorded at the lower of cost or market value, primarily using the average cost method, except for inventory held for trading, which was recorded at fair value up through December 31, 2002 (see discussion below under “Accounting for Risk Management and Trading Activities”). The following table shows the components of inventory.

Inventory (in millions)
	June 30, 2003		December 31, 2002
Materials and supplies	$	340	$	310
Gas		268		271
Petroleum products		56		85
Total inventory	$	664	$	666

Accounting for Risk Management and Trading Activities.All derivatives not qualifying for the normal purchases and normal sales exception under Statement of Financial Accounting Standards (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. Prior to 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 for Contracts Involved in Energy Trading and Risk Management Activities,” on January 1, 2003, certain non-derivative energy trading contracts were also 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 EITF Issue No. 02-03, the Company designated each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge),

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or a normal purchase or normal sale contract, while certain non-trading derivatives remain undesignated. Derivatives related to marketing and other risk management activities are designated as non-trading. Derivatives designated as trading relate to the Company’s proprietary trading activities. As discussed earlier, the Company announced it is exiting proprietary trading at DENA and International Energy.

The Company accounts for both trading and undesignated non-trading derivatives using the mark-to-market accounting method. EITF Issue No. 02-03 requires realized and unrealized gains and losses on all derivative instruments designated as trading to be shown on a net basis in the income statement, but does not provide guidance on the income statement presentation of gains and losses on non-trading derivatives. As discussed below under New Accounting Pronouncements, the EITF has reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to Financial Accounting Standards Board (FASB) Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” EITF Issue No. 03-11 gives guidance on whether realized gains and losses on derivative contracts should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. The consensus on Issue No. 03-11 is not considered final until ratified by the FASB, which is scheduled in August 2003. Gains and losses on non-derivative energy contracts are presented on a gross or net basis in connection with the guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal vs. Net as an Agent.”

For each of the non-trading derivative categories identified above, the Company reports gains and losses or revenue and expense in the Consolidated Statements of Income as follows:

• Gains and losses relating to non-trading derivatives designated as cash flow or fair value hedges are reported on a gross basis, upon settlement, in the same income statement category as the related hedged item.

• Normal purchase or sale contracts are reported on a gross basis upon settlement and recorded in the corresponding income statement category based on commodity type.

• Undesignated non-trading physical purchase or sale derivative contracts, which primarily relate to the Company’s natural gas wholesale marketing operations, are reported on a gross basis, primarily treated as natural gas sales or purchases in the Consolidated Statements of Income.

• Gains and losses from all other undesignated non-trading derivatives are reported on a net basis in trading and marketing net margin within Other Operating Revenues.

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 Other Operating Revenues in the Consolidated Statements of Income. While the income statement presentation of gains and losses or revenue and expense for each category of non-trading derivatives, as 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.

Other Current Liabilities. Through master collateral agreements, counterparties must post cash collateral to the Company and its affiliates for exposure in excess of a contractual threshold. The receipt of cash by the Company creates a current liability on the Consolidated Balance Sheets for the amount received. The amount of this current liability was approximately $540 million as of June 30, 2003 and approximately $330 million as of December 31, 2002 and is included in Other Current Liabilities on the Consolidated Balance Sheets.

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Goodwill.The following table shows the changes in the carrying amount of goodwill for the six months ended June 30, 2003.

Goodwill(in millions)
	Balance December 31, 2002		Other a			Balance June 30, 2003
Natural Gas Transmission	$	2,760	$	(20	)	$	2,740
Field Services		481		9			490
Duke Energy North America		100		—			100
International Energy		246		10			256
Other Operations		6		1			7
Other b		154		—			154
Total consolidated	$	3,747	$	—		$	3,747

^a Amounts consist primarily of foreign currency adjustments 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, “Goodwill and Other Intangible Assets.”

Guarantees. The Company 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 Guarantees of Indebtedness of Others.” In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, the Company recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee. The Company 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.”

Accumulated Other Comprehensive Income (Loss).The following table shows the components of and changes in accumulated other comprehensive income (loss).

Accumulated Other Comprehensive Income (Loss)(in millions)
	Foreign Currency Adjustments			Net Unrealized Gains on Cash Flow Hedges		Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
Balance as of December 31, 2002	$	(653	)	$	455	$	(14	)	$	(212	)
Other comprehensive income changes year to date (net of tax expense of $178)		404			302		—			706
Balance as of June 30, 2003	$	(249	)	$	757	$	(14	)	$	494

Cumulative Effect of Change in Accounting Principles.As of January 1, 2003, the Company adopted the remaining provisions of EITF Issue No. 02-03 and SFAS No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, the Company recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles of $52 million, as a reduction in earnings. See additional discussion of the cumulative effect adjustments below.

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.

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As a result of the consensus on EITF Issue No. 02-03, all non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed on October 25, 2002 and inventories that were recorded at fair values have been adjusted to historical cost via a cumulative effect adjustment of $42 million (net of tax and minority interest) that reduced first quarter 2003 earnings. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods and, therefore, the Company 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 $10 million (net of tax and minority interest) was recorded in the first quarter of 2003, as a reduction in earnings. (For a full discussion of asset retirement obligations, see Note 6.)

New Accounting Standards. SFAS No. 146,“Accounting for Costs Associated with Exit or Disposal Activities.” In June 2002, the FASB issued SFAS No. 146 which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company has adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost was recognized on the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of recognizing future restructuring costs as well as the amounts recognized as liabilities.

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. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is currently assessing the impact of adoption of SFAS No. 149 on its Consolidated Financial Statements.

On June 25, 2003, the FASB cleared the guidance contained in DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.”DIG Issue C20, which applies only to the guidance in paragraph 10(b) of FASB No. 133, and not in reference to embedded derivatives, describes three circumstances in which the underlying in a price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” The guidance in DIG Issue C20 is effective for the Company on October 1, 2003. The Company is currently assessing DIG Issue C20 but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

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, such financial instruments are required to be classified as liabilities in the statement of

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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 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 must be applied to the Company’s existing financial instruments beginning on July 1, 2003. The Company anticipates that the adoption of this statement will not have a material effect on its consolidated results of operations, cash flows or financial position.

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. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company 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 46 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that the Company will disclose information about or consolidate one or more variable interest entities upon the application of FIN 46, primarily as the result of investments it has in certain unconsolidated affiliates. Any significant exposure to losses related to these entities would be related to guarantee obligations as discussed in Note 11. Additionally, see Note 9 for a discussion of the impact of adoption of FIN 46 on the Company’s trust preferred securities. The Company continues to assess FIN 46 but does not anticipate that it will have a material impact on its 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 the relevant facts and circumstances. In analyzing the facts and circumstances, EITF Issue No. 99-19 and APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. Under the EITF’s consensus, transition for this issue would be for transactions or arrangements entered into by the Company after September 30, 2003. The EITF consensus on this issue is not considered final until ratified by the FASB, and the FASB is scheduled to consider ratification of the consensus reached by the EITF in August, 2003. Based upon knowledge of this matter to date, the Company does not anticipate that the adoption of EITF Issue No. 03-11 will have a material effect on its consolidated results of operations, cash flows or financial position.

Reclassifications.Certain prior period amounts have been reclassified to conform to current year presentation, including reclassifications between certain of the individual line items in the operating revenues section of the Consolidated Statements of Income related to the Company’s continued enhancement of its methodologies around the application of EITF Issue No. 02-03.

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3. Business Acquisitions and Dispositions

Acquisitions.The Company 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 is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on asset and liability valuations becomes available within one year after the acquisition.

On March 14, 2002, the Company acquired Westcoast Energy Inc (Westcoast) for approximately $8 billion, including the assumption of $4.7 billion of debt. The Westcoast acquisition was accounted for using the purchase method, and goodwill of approximately $2.3 billion was recorded in the transaction, of which approximately $57 million is 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 the first quarter of 2003, the Company recorded additional purchase price adjustments as information regarding the assets acquired became available, including adjustments related to the sale of Empire State Pipeline to National Fuel Gas Company. The purchase price amounts in the following table reflect the additional purchase price adjustments and the adjustments for the sale of Empire State Pipeline.

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

Purchase Price Allocation for Westcoast Acquisition(in millions)
Current assets	$	2,050
Investments and other assets		1,207
Goodwill		2,253
Property, plant and equipment		4,991
Regulatory assets and deferred debits		809
Total assets acquired		11,310
Current liabilities		1,655
Long-term debt		4,132
Deferred credits and other liabilities		1,662
Minority interests		560
Total liabilities assumed		8,009
Net assets acquired	$	3,301

Operating revenues would have been $4,925 million and net income would have been $450 million for the six months ended June 30, 2002 if the Westcoast acquisition had taken place at January 1, 2002.

Dispositions.In first quarter 2003, the Company sold limited partnership interests in Northern Borders L.P. for approximately $24 million. The Company recorded a pre-tax gain of approximately $14 million.

In April 2003, the Company closed on substantially all elements of a transaction to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $250 million. This sale resulted in a pre-tax gain of approximately $31 million. The transaction was completed except for the Company’s small ownership interest related to the U.S. segment of Alliance Pipeline, which is expected to close in October 2003 and represents approximately $11 million in proceeds. The Company obtained its minority ownership

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interest in the Alliance natural gas pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant through its acquisition of Westcoast in 2002.

In April 2003, the Company sold all its Class B units of TEPPCO Partners, L.P. (TEPPCO) for approximately $114 million. The Company recorded a pre-tax gain of approximately $11 million on the sale. TEPPCO is a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil, gathers and processes natural gas, and fractionates and transports natural gas liquids.

In May and June 2003, DEFS sold one package of assets to Crosstex Energy Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy, LLC (ScissorTail) for a total sales price of approximately $90 million. The gain on these sales was approximately $26 million ($18 million at the Company’s approximately 70% share). The assets sold to Crosstex consisted of the AIM Pipeline System in Mississippi; a 12.4% interest in the Seminole gas processing plant in Texas; the Conroe gas plant and gathering system in Texas; the Black Warrior pipeline system in Alabama; and two smaller systems—Aurora Centana and Cadeville in Louisiana. The assets sold to ScissorTail consisted of various gas processing plants and gathering pipeline in eastern Oklahoma.

In June 2003, DENA closed an agreement to sell its 50% ownership interest in Duke/UAE Ref-Fuel for $306 million to Highstar Renewable Fuels LLC. The Company recorded a gain on the sale of approximately $175 million.

4. Business Segments

The Company’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for the Company’s segments are the same as those described in Note 2. Management evaluates segment performance primarily based on earnings before interest and taxes (EBIT) after deducting minority interests.

EBIT on a consolidated basis is viewed as a non-GAAP measure under the rules of the Securities and Exchange Commission (SEC). The Company has included EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance. On a segment basis, EBIT represents all profits (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash and cash equivalents are managed centrally by the Company. Since the business units do not manage those items, the gains and losses on foreign currency remeasurement associated with cash balances and third-party interest income on those balances are generally excluded from the segments’ EBIT. Management considers EBIT to be a good indicator of each segment’s operating performance, as it represents the results of the Company’s ownership interests in operations without regard to financing methods or capital structures.

On a consolidated basis, EBIT is also used as one of the measures to assess performance and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Income. The use of EBIT as one of the performance measures on a consolidated basis follows the use of EBIT for assessing segment performance, and the Company believes EBIT is used by its investors as a supplemental financial measure in the evaluation of the Company’s consolidated results of operations.

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The following table shows the components of EBIT and reconciles consolidated operating income and EBIT to net income.

Reconciliation of Operating Income to Net Income(in millions)
	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003			2002
Operating income	$	489	$	499	$	1,047		$	838
Other income and expensesa		276		132		347			211
EBIT		765		631		1,394			1,049
Interest expense		272		217		550			357
Minority interest expense		49		52		90			73
Earnings before income taxes		444		362		754			619
Income taxes		147		123		250			206
Income before cumulative effect of change in accounting principles		297		239		504			413
Cumulative effect of change in accounting principles, net of tax and minority interest		—		—		(52	)		—
Net income	$	297	$	239	$	452		$	413

^a Includes gains on sale of equity investments

EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. The Company’s EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

In the following table, EBIT includes the profit on intersegment sales at prices management believes are representative of arms-length transactions. Beginning in 2003, the business segments formerly known as Other Energy Services and Duke Ventures were combined and have been presented as Other Operations (see Note 1 for detailed descriptions of the segments). The “Other” line item primarily includes certain unallocated corporate costs, and the elimination of intercompany profits from earnings at D/FD for energy plants it has under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

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Business Segment Data(in millions)
	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures
Three Months Ended June 30, 2003
Natural Gas Transmission	$	636		$	56		$	692		$	306		$	98	$	233
Field Services		1,834			90			1,924			76			76		31
Duke Energy North America		737			47			784			204			61		97
International Energy		366			—			366			111			27		18
Total reportable segments		3,573			193			3,766			697			262		379
Other Operations		177			1			178			27			8		76
Other		10			36			46			(15	)		4		(41	)
Eliminations and minority interests		—			(230	)		(230	)		46			—		—
Third-party interest income		—			—			—			2			—		—
Foreign currency remeasurement gain		—			—			—			8			—		—
Total consolidated	$	3,760		$	—		$	3,760		$	765		$	274	$	414
Three Months Ended June 30, 2002
Natural Gas Transmission	$	579		$	42		$	621		$	313		$	90	$	253
Field Services		1,075			301			1,376			41			71		74
Duke Energy North America		605			(276	)		329			124			39		785
International Energy		217			2			219			57			29		136
Total reportable segments		2,476			69			2,545			535			229		1,248
Other Operations		179			(31	)		148			102			7		158
Other		—			97			97			(68	)		2		(36	)
Eliminations, reclassifications and minority interests		(256	)		(135	)		(391	)		42			—		—
Third-party interest income		—			—			—			12			—		—
Foreign currency remeasurement gain		—			—			—			8			—		—
Total consolidated	$	2,399		$	—		$	2,399		$	631		$	238	$	1,370

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Business Segment Data(in millions)
	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures
Six Months EndedJune 30, 2003
Natural Gas Transmission	$	1,515		$	145		$	1,660		$	729		$	194	$	431
Field Services		3,783			594			4,377			109			154		62
Duke Energy North America		1,870			135			2,005			225			119		257
International Energy		748			—			748			165			52		43
Total reportable segments		7,916			874			8,790			1,228			519		793
Other Operations		257			2			259			47			15		137
Other		11			38			49			19			7		3
Eliminations and minority interests		—			(914	)		(914	)		92			—		—
Third-party interest income		—			—			—			5			—		—
Foreign currency remeasurement gain		—			—			—			3			—		—
Total consolidated	$	8,184		$	—		$	8,184		$	1,394		$	541	$	933
Six Months Ended June 30, 2002
Natural Gas Transmission	$	1,001		$	70		$	1,071		$	579		$	144	$	2,290
Field Services		2,007			503			2,510			76			145		184
Duke Energy North America		1,042			(457	)		585			170			68		1,521
International Energy		505			3			508			114			52		217
Total reportable segments		4,555			119			4,674			939			409		4,212
Other Operations		308			3			311			106			12		284
Other		—			93			93			(117	)		5		—
Eliminations, reclassifications and minority interests		(256	)		(215	)		(471	)		56			—		—
Third-party interest income		—			—			—			48			—		—
Foreign currency remeasurement gain		—			—			—			17			—		—
Cash acquired in acquisitions		—			—			—			—			—		(77	)
Total consolidated	$	4,607		$	—		$	4,607		$	1,049		$	426	$	4,419

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

Segment Assets(in millions)
	June 30, 2003		December 31, 2002
Natural Gas Transmission	$	15,926	$	15,168
Field Services		6,982		6,992
Duke Energy North America		16,977		16,272
International Energy		5,736		5,804
Total reportable segments		45,621		44,236
Other Operations		2,205		2,316
Other, net of eliminations		1,621		1,013
Total consolidated	$	49,447	$	47,565

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5. Regulatory Matters

Regulatory Assets and Liabilities. In the first quarter of 2003, the Company adopted SFAS No. 143, which applies to legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs (see Note 6). Certain of the Company’s regulated operations recognize some removal costs as a component of accumulated depreciation for property that does not have an associated legal retirement obligation, in accordance with regulatory treatment. As of June 30, 2003, the amount of accumulated depreciation on the Consolidated Balance Sheet related to this regulatory liability is approximately $16 million.

Notices of Proposed Rulemaking (NOPR). NOPR on Amendments to Blanket Sales Certificates and Order Proposing to Amend Market-Based Tariffs and Authorizations. In June 2003, the FERC issued two proposals that would require that market participants who operate under market-based rates for blanket sales certificates for gas sales comply with new behavioral constraints and reporting requirements. The proposals would require compliance with market rules and codes of conduct addressing market manipulation, price reporting and record retention. In addition, sellers reporting to index publishers would be required to do so with certainty and completeness and verify this practice with the FERC. Violation of the new conditions could result in disgorgement of unjust profits or suspension or revocation of a company’s tariff or certificate. These proposals follow from the FERC’s Staff March 26, 2003 Final Report on Price Manipulation in Western Markets. Comments on the FERC’s proposed conditions are due August 18, 2003. The Company is reviewing the proposals and preparing an appropriate response to the FERC.

Interim Rule on Cash Management Practices. In June 2003, the FERC issued an Interim Rule and additional proposed changes that would require cash management program documentation for FERC-regulated entities. The Interim Rule requires that FERC-regulated entities maintain written records of their cash management programs. Additionally, a proposal for comment would require two additional conditions: FERC-regulated entities would be required to file their cash management agreements with the FERC; and FERC-regulated entities would be required to notify the FERC when their proprietary capital ratio drops below 30% of total capitalization and when the capital ratio subsequently returns to or exceeds 30%. The Company filed comments with the FERC on August 7, 2003.

6. 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 the Company relate primarily to the retirement of certain gathering pipelines and processing facilities, the retirement of some gas-de-capfired 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, the Company 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.

Certain of the Company’s regulated operations recognize some removal costs as a component of depreciation in accordance with regulatory treatment. While these amounts will remain in accumulated

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depreciation, to the extent they do not represent SFAS No. 143 legal retirement obligations, they are disclosed as part of the regulatory matters footnote.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by the Company on January 1, 2003. As of January 1, 2003, the implementation of SFAS No. 143 resulted in a net increase in total assets of $43 million, consisting primarily of an increase in net property, plant and equipment. Liabilities increased by $53 million, primarily representing the establishment of an asset retirement obligation liability of $69 million, reduced by the amount that was already recorded for a cost of removal. For obligations related to non-regulated operations, a net-of-tax cumulative effect of change in accounting principle adjustment of $10 million was recorded in the first quarter of 2003 as a reduction in earnings.

The following table shows the asset retirement obligation liability as though SFAS No. 143 had been in effect for the three prior years.

Pro forma Asset Retirement Obligation Liability(in millions)
January 1, 2000	$	19
December 31, 2000		37
December 31, 2001		46
December 31, 2002		69

The pro forma net income effect of adopting SFAS No. 143 is not shown due to its immaterial impact.

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table shows the reconciliation of the asset retirement obligation liability for the six-month period ended June 30, 2003.

Reconciliation of Asset Retirement Obligation Liability for the Six-Month Period Ended June 30, 2003(in millions)
Balance as of January 1, 2003	$	69
Accretion expense		3
Balance as of June 30, 2003	$	72

7. Risk Management Instruments, Hedging Activities and Credit Risk

The Company, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its proprietary trading activities. The Company 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 for trading purposes. On April 11, 2003, the Company announced that it will be exiting proprietary trading at DENA and International Energy. The Company is also exposed to the impact of market fluctuations in commodity prices and interest rates as a result of its ownership of energy related assets and interest in structured contracts, as well as use of certain interest rate hedge instruments. The use of undesignated non-trading derivatives to manage these risks is reflected as other than trading.

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The following table shows the fair value of the Company’s derivative portfolio as of June 30, 2003 and December 31, 2002.

Derivative Portfolio Fair Value (in millions)
	June 30, 2003		December 31, 2002
Trading	$	234	$	312
Other than Trading		91		—
Hedging		1,133		691
Total	$	1,458	$	1,003

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 the Consolidated Balance Sheets.

Commodity Cash Flow Hedges. As of June 30, 2003, $295 million of after-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 Accumulated Other Comprehensive Income (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.

Credit Risks. In addition to the risk associated with the market fluctuation in the price of natural gas, electricity and other energy-related products marketed and purchased, the Company is exposed to the risk of loss resulting from non-performance of contractual obligations by a counterparty. During 2003, certain counterparties who have contractual arrangements with the Company have either encountered financial difficulty or declared bankruptcy. The Company has taken active measures, such as the modification of collateral agreements and modification of existing contracts, to mitigate the risks associated with such counterparties and as of June 30, 2003, has not realized material losses from non-performance of such counterparties. While the Company has processes in place to monitor and attempt to mitigate economic exposures to these counterparties, the energy sector remains financially distressed.

8. Debt and Credit Facilities

In March 2003, DEFS entered into a $100 million funded short-term loan with Bank One, NA. This short-term loan matures in September 2003, and may be repaid at any time. This short-term loan has an interest rate equal to, at DEFS’ option, either (1) the London Interbank Offered Rate plus 1.35% per year or (2) the higher of (a) the Bank One, NA prime rate and (b) the Federal Funds rate plus 0.50% per year. Subsequent to June 30, 2003, DEFS repaid the entire short-term loan with funds generated from assets sales and operations.

During 2003, $500 million of commercial paper that had been included in Long-term Debt on the December 31, 2002 Consolidated Balance Sheet was reclassified as Notes Payable and Commercial Paper. This reclassification reflects the Company’s intention to no longer maintain a significant outstanding long-term portion of commercial paper.

During the six-month period ended June 30, 2003, DEFS, Duke Australia Finance Pty Ltd. (a wholly owned subsidiary of the Company) and the Company replaced expiring credit facilities. The credit facilities that have replaced the expired credit facilities are included in the following table which summarizes the Company’s credit facilities and related amounts outstanding as of June 30, 2003. The majority of the credit facilities support commercial paper programs. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

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Credit Facilities Summary as of June 30, 2003(in millions)	Expiration Date	Credit Facilities Available
				Amounts Outstanding
				Commercial Paper		Letters of Credit		Other Borrowings		Total
Duke Capital Corporation
$700 364-day syndicateda, b, c	August 2003
$142 364-day bilaterala, b, c	August 2003
$253 364-day syndicated letter of credita, b, c	April 2004
$538 multi-year syndicated letter of creditb, c	April 2004
$550 multi-year syndicateda, b, c	August 2004
Total Duke Capital Corporation		$	2,183	$	161	$	567	$	—	$	728
Westcoast Energy Inc.
$185 364-day syndicateda, b	December 2003
$148 two-year syndicatedb	December 2004
Total Westcoast Energy Inc.d			333		—		—		—		—
Union Gas Limited
$444 364-day syndicatede	July 2003		444		—		—		—		—
Duke Energy Field Services, LLC
$350 364-day syndicateda, c, f	March 2004		350		—		—		—		—
Duke Australia Finance Pty Ltd.
$211 364-day syndicatedg	March 2004		211		113		—		72		185
Duke Australia Pipeline Finance Pty Ltd.
$208 multi-year syndicatedh	February 2005		208		—		—		189		189
Total		$	3,729	$	274	$	567	$	261	$	1,102

^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 of two-and-a-half times or greater.

^d Credit facilities are denominated in Canadian dollars, and totaled 450 million Canadian dollars as of June 30, 2003.

^e Credit facility contains an option allowing up to 50% of the amount of the facility to be borrowed on the day of initial expiration for up to one year. 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 600 million Canadian dollars as of June 30, 2003. In July 2003, credit facility matured and was replaced with a 364-day credit facility for 340 million Canadian dollars (U.S. $243 million as of the transaction date) with a July 2004 expiration. In addition, this credit facility contains an option allowing it to be converted to a one-year term loan upon its expiration.

^f Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 53%.

^g Credit facility is guaranteed by the Company. Credit facility is denominated in Australian dollars, and was 316 million Australian dollars as of June 30, 2003.

^h Credit facility is guaranteed by the Company. Credit facility is denominated in Australian dollars, and totaled 312 million Australian dollars as of June 30, 2003. Duke Australia Pipeline Finance Pty Ltd. is a wholly owned subsidiary of the Company.

In addition to the existing credit facilities, the Company has a separate option to borrow up to $200 million between June 30, 2003 and August 29, 2003. Any amounts borrowed under this option would be due no later than March 31, 2004. Also, the Company is currently maintaining a minimum cash position of $500 million to be used for short-term liquidity needs. This cash position is invested in highly rated, liquid, short-term money market securities.

As of June 30, 2003, the Company has approximately $1,475 million of credit facilities that will mature in the last six months of 2003. The Company intends to continue to reduce its need for these credit facilities throughout the remainder of 2003, and thus resyndicate less than the total $1,475 million.

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The Company’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in acceleration of due dates of certain borrowings and/or termination of the agreements. As of June 30, 2003, the Company was in compliance with those covenants. In addition, certain of the agreements contain cross-acceleration provisions that may allow acceleration of payments or termination of the agreements upon nonpayment or acceleration of other significant indebtedness of the applicable borrower or certain of its subsidiaries.

Additionally, the Company may be required to repay certain debt should their credit ratings fall to a certain level at Standard & Poors or Moody’s Investor Service. In June 2003, the Company’s senior unsecured debt ratings fell below Baa2 to Baa3 at Moody’s. As a result, the holder of $150 million of 4.732% senior unsecured bonds due in December 2003 has the option to require early repayment of the notes. The holder of the bonds has indicated that there are no current plans to exercise its option.

As of June 30, 2003, the Company and its subsidiaries had effective SEC shelf registrations for up to $1,000 million in gross proceeds from debt and other securities. Additionally, as of June 30, 2003, the Company had access to 950 million Canadian dollars (U.S. $703 million) available under Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Subsequent to June 30, 2003, the shelf registration for 750 million Canadian dollars expired. It is expected that the expired shelf registration will be renewed for 500 million Canadian dollars during the third quarter of 2003. The shelf registration associated with the remaining 200 million Canadian dollars will expire in June 2004.

9. Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation

In June 2003, the Company redeemed all of its 7.375% trust preferred securities due in 2038. The total redemption price was approximately $250 million.

Upon the implementation of FIN 46 effective July 1, 2003, the trusts that hold the Company’s trust preferred securities will be deconsolidated since the Company is not the primary beneficiary of the related trusts. Therefore, this deconsolidation will result in the Company reflecting a liability for the note payable to the trusts, which was previously eliminated in consolidation. As a result, the amortization of the related debt discount and interest payments associated with the notes payable will be classified on the Consolidated Statements of Income as Interest Expense rather than Minority Interest Expense.

10. Commitments and Contingencies

Litigation.Western Power Disputes.Several investigations and regulatory proceedings at the state and federal levels are looking into the causes of high wholesale electricity prices in the western U.S. during 2000 and 2001. As a result, the FERC has 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 June 2001, DETM offset approximately $20 million against amounts owed by the California Independent System Operator (CAISO) and the California Power Exchange (CalPX) for electricity sales during January and February 2001. This offset reduced the $110 million reserve established in 2000 to $90 million. The Company continues to believe this reserve is appropriate. No additional provisions for California receivables and market risk were recorded in 2001 or 2002. In December 2002, the presiding administrative law judge in the FERC refund proceedings issued his proposed findings with respect to the mitigated market clearing price, including his preliminary determinations of the refund liability of each seller of electricity in the CAISO and the CalPX. These proposed findings estimated that DETM has refund liability of approximately $95 million in the aggregate to both the CAISO and CalPX. This would be offset against the remaining receivables still owed to DETM by the CAISO and CalPX. The proposed findings were the presiding judge’s estimates only, and are subject to further recalculation and adoption by the FERC in connection with its ongoing wholesale pricing investigation. (See Note 13 to the Consolidated Financial

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Statements, “Commitments and Contingencies—Litigation, Western Power Disputes, Other Proceedings,” in the Company’s Form 10-K/A for December 31, 2002 for additional information on these matters.) On March 3, 2003, various parties (including the California attorney general) filed at the FERC seeking modification of the FERC’s refund orders and alleging that DETM and others manipulated wholesale electricity prices in periods prior to the initial refund period. DETM filed responses denying the California parties’ allegations.

On March 26, 2003, the FERC issued staff recommendations relating to the FERC’s investigation into the causes of high wholesale electricity prices in the western U.S. during 2000 and 2001, and an order in the FERC’s refund proceeding. The recommendations and order address, among other things: modifying the presiding judge’s refund findings with respect to the gas price component and certain other components of the refund calculation; issuance of show cause orders related to certain energy trading practices; requiring trading entities to demonstrate that they have corrected their internal processes for reporting trading data to the Trade Press in order to continue selling natural gas at wholesale (see “Trading Matters” below); and establishing a ban on prearranged “round trip” trades as a condition of blanket certificates (see Note 13 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation, Trading Matters,” in the Company’s Form 10-K/A for December 31, 2002 for additional information on “round-trip” trading). The March 26, 2003 FERC Order modified the prior refund methodology by changing the gas proxy price used in the refund calculation. In connection with the issuance of the March 26, 2003 order, the FERC announced that the result of the calculation methodology change could result in a doubling of the prior refund amount. But, the order allowed generators to receive a gas cost credit in instances where companies incurred fuel costs exceeding the gas proxy price. Pursuant to this provision of the order, DENA and DETM, along with other suppliers, provided gas cost data to the FERC. DENA and DETM’s filing states that DENA and DETM are entitled to a gas price credit in the range of $72 million. The California parties are challenging both the amount and availability of the credit. The FERC has not ruled on the gas credit issues nor has it ruled on numerous requests for rehearing, clarification, and the like, filed by parties since the issuance of the order.

DETM also was included in a group of 11 parties required to make written demonstrations regarding index price reporting practices. The Order required DETM to state the disciplinary actions taken, identify its code of conduct for price submissions, show that its submission practices lack financial conflicts of interest and show that it is cooperating with related government investigations. The FERC announced on July 23, 2003 that it “accepted” DETM’s account of internal remedies for reporting natural gas trading data and stated that DETM met the order’s requirements.

In late June 2003, the FERC issued an Order to Show Cause concerning Enron-type gaming behavior. The FERC is encouraging parties to consider settlement of these issues and is requiring parties to attend settlement discussions with the FERC trial staff. DETM is complying with the FERC’s request, but will continue to vigorously defend its conduct in the Western markets. In a companion Order, the FERC has required suppliers, including DETM, to justify bids in the CAISO and CalPX markets made above the level of $250 per megawatt during the period May 1, 2000 through October 1, 2000. DETM is responding to the staff’s data requests.

On August 1, 2003, the FERC staff issued a supplemental report regarding its investigation to determine whether generators located in California physically withheld energy from the California market to affect prices during the period from May 1, 2000, to June 30, 2001. The FERC staff concluded that DENA, a market participant with substantial generation resources in California, explained the reasons for any outages at DENA facilities during the relevant period such that DENA will not be subject to further investigation regarding this matter absent new information.

Related Litigation.In December 2002, plaintiffs filed class-action suits against Duke Energy and numerous other energy companies in state court in Oregon and in federal court in Washington state making allegations similar to those in the California suits (see Note 13 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation,” in the Company’s Form 10-K/A for December 31, 2002 for additional information on California litigation). Plaintiffs allege they paid unreasonably high prices for electricity and/or natural gas during the time period from January 2000 to the present as a result of

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defendants’ activities which were fraudulent, negligent and in violation of each state’s business practices laws. Those suits have been dismissed. On April 28, 2003, five individuals from three states filed a class action lawsuit against Duke Energy and numerous other energy companies in Superior Court of the State of California, San Diego, County, on behalf of purchasers of electric and/or natural gas energy residing in the states of Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana. On June 30, 2003, the Attorney General of the State of Montana, for the state and its citizens, and a rural electric cooperative filed suit in the First Judicial District of Montana, County of Lewis and Clark, against numerous energy companies including DETM. Plaintiffs claim that wholesale and retail pricing throughout the “West Coast Energy Market” is dominated by trading and pricing in California and allege that defendants, acting unilaterally and in concert with other energy companies, engaged in manipulation of the supply of energy into the California markets, resulting in artificially high electricity prices. Plaintiffs, also alleging that defendants’ actions were in violation of California’s antitrust and unfair business practices laws, seek actual and treble damages; restitution of funds acquired by unfair or unlawful means; an injunction prohibiting the defendants from engaging in the alleged unlawful activity; and other appropriate relief.

Seven class action lawsuits were filed against Duke Energy entities in California state courts in May and June 2003 alleging generally that defendants, alone and in concert with others, manipulated the natural gas markets by various means, including, in some suits, engaging in “wash” trades, providing false information to natural gas trade publications, and unlawfully exchanging information, resulting in artificially high energy prices. Alleging that defendants are in violation of California’s antitrust and unfair business practices laws, plaintiffs seek class action certification, unspecified compensatory and treble damages, restitution and disgorgement of unfairly or unlawfully obtained monies, an order prohibiting the defendants from engaging in the alleged unlawful conduct, attorneys’ fees and costs, and other appropriate relief.

Trade publications.In November 2002, the Lieutenant Governor of the State of California, on behalf of himself, the general public and taxpayers of California, filed a class-action suit against the publisher of natural gas trade publications and numerous other defendants, including seven Company entities, in state court in Los Angeles, alleging that the defendants engaged in various unlawful acts, including artificially inflating the index prices of natural gas reported in industry publications through collusive behavior, and have thereby violated state business practices laws. The plaintiffs seek an order prohibiting the defendants from engaging in the acts complained of, restitution, disgorgement of profits acquired through defendants’ alleged unlawful acts, an award of civil fines, compensatory and punitive damages in unspecified amounts and other appropriate relief. On July 8, 2003, the court issued an opinion granting the motions of defendants to dismiss the complaint on filed rate and preemption grounds. In so ruling, the court granted leave to the plaintiffs to amend the complaint with certain restrictions so as not to contravene the intent of the ruling.

Sacramento Municipal Utility District (SMUD) and City of Burbank, California FERC Complaints.In July 2002 and August 2002, respectively, the SMUD and the City of Burbank, California filed complaints with the FERC against DETM and other providers of wholesale energy requesting that the FERC mitigate alleged unjust and unreasonable prices in sales contracts entered into between DETM and the complainants in the first quarter of 2001. The complainants, alleging that DETM had the ability to exercise market power, claim that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the western markets to be dysfunctional and uncompetitive and that the western markets influenced their price. In support of their request to mitigate the contract price, the complainants rely on the fact that the contract prices are higher than prices in the West following implementation of the FERC’s June 2001 price mitigation plan. The complainants request the FERC to set “just and reasonable” contract rates and to promptly set a refund effective date. In September 2002, the FERC issued an order in the Sacramento matter setting forth, in part, that the matter be set for an evidentiary hearing to be held in abeyance until the parties engage in settlement negotiations and that a refund effective date of September 22, 2002 be established. DETM participated in settlement proceedings and reached a settlement with the SMUD in February 2003. In February 2003, the SMUD filed to withdraw its FERC complaint against DETM. On March 10, 2003, the FERC issued an order in the Burbank matter setting forth, in part, that the matter be set for an evidentiary hearing to be held in abeyance until the parties engage in settlement negotiations, and that a refund effective date of October 11, 2002 be

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established. Pursuant to a March 20, 2003 order from the FERC, the parties to the Burbank proceeding engaged in settlement discussions. In June 2003, DETM and the City of Burbank executed a settlement agreement, and the City withdrew its FERC complaint against DETM.

Trading Matters. Since April 2002, 17 shareholder class-action lawsuits have been filed against Duke Energy: 13 in the United States District Court for the Southern District of New York and four in the United States District Court for the Western District of North Carolina. The 13 lawsuits pending in New York were consolidated into one action and included as co-defendants Duke Energy executives and two investment banking firms. In December 2002, the New York court granted in all respects the defendants’ motion to dismiss the plaintiffs’ claims. The four lawsuits pending in North Carolina name as co-defendants Duke Energy executives. Two of the four North Carolina suits were consolidated. This consolidated case involved claims under the Employee Retirement Income and Security Act relating to Duke Energy’s Retirement Savings Plan. This consolidated action named Duke Energy board members as co-defendants. In late June 2003, the federal court in North Carolina dismissed with prejudice the consolidated ERISA-based action. The plaintiffs have appealed the dismissal. All but two of the original 17 shareholder suits now have been dismissed. In addition, Duke Energy has received three shareholder derivative notices demanding that it commence litigation against named executives and directors of Duke Energy for alleged breaches of fiduciary duties and insider trading. Duke Energy’s response to the derivative demands is not required until 90 days after receipt of written notice requesting a response.

The class-action lawsuits and the threatened shareholder derivative claims arise 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. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys’ fees and costs for alleged violations of securities laws. Duke Energy intends to vigorously defend itself, the Company and its named executives and board members against these allegations and will seek dismissal of the remaining two suits. In July 2003, a former trader with Duke Energy Merchants, LLC (DEM), an affiliate of the Company, brought a lawsuit against Duke Energy, DENA and DEM in federal court in the Southern District of Texas that contains allegations of round trip trading and accounting issues. The lawsuit asserts claims of securities fraud relating to options and stock acquired by him as part of his compensation package, as well as additional claims relating to his employment.

In October 2002, the FERC issued a data request to the “Largest North American Gas Marketers, As Measured by 2001 Physical Sales Volumes (Bcf/d),” including DETM. In general, the data request asks for information concerning natural gas price data submitted by the gas marketers to publishers of natural gas price indices. DETM responded to the FERC’s data request, and is also responding to requests by the Commodities Future Trading Commission (CFTC) for similar information. The March 26, 2003 FERC staff recommendations (see “Western Power Disputes” above) included a report on the FERC’s investigation regarding information provided to publications. The report noted that the practice in the Company’s Salt Lake City office was to report actual transactions while the practice in the Houston office was to report a sense of the market while sometimes taking the Company’s open positions into account. The FERC staff report also identified controls that should be implemented to address inaccurate reporting of information to trade publications. The Company has implemented the controls identified in the report. Management is unable to predict the outcome of any actions the FERC or the CFTC may take with respect to these matters.

Sonatrach/Citrus Trading Corporation (Citrus). Duke Energy LNG Sales, Inc. (Duke LNG) claims in this arbitration that Sonatrach, the Algerian state-owned energy company, together with its liquefied natural gas (LNG) sales and marketing subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), have breached their obligations to provide shipping under an LNG Purchase Agreement and related Transportation Agreements (the Sonatrach Agreements) relating to Duke LNG purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Sonatrading and Sonatrach, on the other hand, claim that Duke LNG repudiated the Sonatrach Agreements as a result of, among other things, Duke LNG alleged failure to diligently seek commitments from customers, and to submit offers to Sonatrading based on such commitments, for the purchase of LNG from Sonatrading.

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The arbitration was bifurcated into liability and damages phases, with the liability phase concluding in March 2003. On July 11, 2003, the Tribunal issued its Partial Award on liability issues, finding that Sonatrach and Sonatrading had breached their obligations to provide shipping, rendering them liable to Duke LNG for any resulting damages. The Tribunal also found that Duke LNG had breached the LNG Purchase Agreement with Sonatrading by failing to diligently seek commitments from customers, by failing to submit certain offers to purchase LNG to Sonatrading and by failing to maintain access to sufficient LNG terminalling capacity at the Lake Charles regasification facility. Sonatrading has recently terminated the Sonatrach Agreements and seeks in the arbitration to recover resulting damages from Duke LNG. The damages phase of this proceeding has not yet been scheduled. Management believes that the final disposition of this arbitration will have no material adverse effect on the consolidated results of operations, cash flows or financial position.

In a matter related to the Sonatrach arbitration, Citrus filed suit in March 2003 against Duke LNG in the District Court of Harris County, Texas. The suit alleged that Duke LNG breached the parties’ natural gas purchase contract (the Citrus Agreement) by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that as a result of Sonatrach’s actions, Duke LNG experienced a loss of LNG supply that affects Duke LNG’s obligations and termination rights under the Citrus Agreement. The Citrus petition seeks unspecified damages and a judicial determination that contrary to Duke LNG’s position, Duke LNG has not experienced a loss of LNG supply. Duke LNG subsequently terminated the Citrus Agreement and filed a counterclaim in the Texas action asserting that Citrus breached the terms of the Citrus Agreement by, among other things, failing to provide sufficient security for the gas transactions. Citrus has denied that Duke LNG has the right to terminate the agreement and has recently stated in correspondence between the parties that Duke LNG’s termination of the agreement was itself a breach entitling Citrus to resulting damages. Both parties, however, accept the fact that the Citrus Agreement has come to an end. Duke LNG continues to evaluate the claims at issue in this matter and intends to vigorously defend itself.

Enron Bankruptcy.In December 2001, Enron filed for relief pursuant to Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Additional affiliates have filed for bankruptcy since that date. Certain affiliates of the Company engaged in transactions with various Enron entities prior to the bankruptcy filings. DETM was a member of the Official Committee of Unsecured Creditors in the bankruptcy cases which are being jointly administered, but as of February 2003, DETM resigned from the Official Committee of Unsecured Creditors in the Enron bankruptcy case. In 2001, the Company recorded a reserve to offset its exposure to Enron.

In mid-November 2002, various Enron trading entities demanded payment from DETM for certain energy commodity sales transactions without regard to the set-off rights of DETM, and demanded that DETM detail balances due under certain master trading agreements without regard to the set-off rights of DETM. On December 13, 2002, DETM filed an adversary proceeding against Enron, seeking, among other things, a declaration affirming each plaintiff’s right to set off its respective debts to Enron. The complaint alleges that the Enron affiliates were operated by Enron as its alter-ego and as components of a single trading enterprise, and that DETM should be permitted to exercise their respective rights of mutual set-off against the Enron trading enterprise under the Bankruptcy Code. The complaint also sought the imposition of a constructive trust, so that any claims by Enron against DETM would be subject to the respective set-off rights of DETM. On April 17, 2003, DETM’s adversary proceeding was dismissed by the bankruptcy judge for lack of standing. On April 30, 2003, DETM filed their notice of appeal of this decision. Oral argument on the appeals is scheduled for September 19, 2003.

Management believes that the final disposition of the Enron bankruptcy will have no material adverse effect on consolidated results of operations or financial position.

Other Litigation and Legal Proceedings.The Company and certain of its subsidiaries are involved in other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies 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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Sale-Leaseback Transaction. In May 2003, the Company entered into an agreement to sell its 5400 Westheimer Court office building in Houston, Texas to an unrelated third-party for approximately $78 million. This is a sale-leaseback transaction whereby the Company sold the building but will lease it back over a 15-year lease term. The lease expires in April 2018, with two five-year extensions exercisable at the Company’s option. The Company may also terminate the lease early, in April 2016, without penalty. The future minimum lease payments under the lease are approximately $100 million. The Company does not have an option to purchase the leased facilities at the end of the minimum lease term and has not issued any residual value guarantee of the value of the leased facilities. As such, the gain on the sale of approximately $17 million will be amortized over the minimum term of the lease, which has been accounted for as an operating lease by the Company.

11. Guarantees and Indemnifications

The Company and certain of 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. The Company 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) in which DCS will design, construct, operate and deactivate a MOX fuel fabrication facility (MOX FFF). The domestic MOX fuel project was prompted by an agreement between the U.S. 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, 2003, the Company, through its indirect wholly owned subsidiary, Duke Project Services Group, Inc. (DPSG), held a 40% ownership interest in DCS. Additionally, Duke Power, an affiliate of the Company, has entered into a subcontract with DCS (the Duke Power Subcontract) to prepare the McGuire and Catawba nuclear reactors (the Nuclear Reactors) for use of the MOX fuel and to provide for certain terms and conditions applicable to the purchase of MOX fuel produced at the MOX FFF for use in the Nuclear Reactors.

As required under the Prime Contract, DPSG and the other owners of DCS have issued a guarantee to the DOE (the DOE Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to the DOE all of DCS’ payment and performance obligations under the Prime Contract. The Prime Contract consists of a “Base Contract” phase and three option phases. The DOE has the right to extend the term of the Prime Contract to cover the three option phases on a sequential basis, subject to DCS and DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. Each of the three option phases will be negotiated separately, as the time for exercising each option phase becomes due under the Prime Contract. If the DOE does not exercise its right to extend the term of the Prime Contract to cover any or all of the option phases, DCS’ performance obligations under the Prime Contract will end upon completion of the then-current performance phase. Additionally, the DOE has the right to terminate the Prime Contract for convenience at any time. Under the Base Contract phase, which covers the design of the MOX FFF and design modifications to the Nuclear Reactors, DCS is to receive cost reimbursement plus a fixed fee. The first option phase includes construction and cold startup of the MOX FFF and modification of the Nuclear Reactors, and provides for DCS to receive cost reimbursement plus an incentive fee. The second option phase provides for taking the MOX FFF from cold to hot startup, operation of the MOX FFF, and irradiation of the MOX fuel in the Nuclear Reactors. For the second option phase, DCS is to receive a cost reimbursement plus an incentive fee through hot startup and, thereafter, cost-sharing plus a fee. The third option phase involves DCS’ deactivation of the MOX FFF in exchange for a fixed price payment. As of June 30, 2003, DCS’ performance obligations under the Prime Contract include only the Base Contract phase, since the DOE has not yet exercised its option to extend the term of performance under the Prime Contract to the first option phase, and DCS and the DOE have not yet agreed on all open terms and conditions applicable to that phase.

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Additionally, DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) under which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ payment and performance obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. The Duke Power Subcontract consists of a “Base Subcontract” phase and two option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the two 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. Under the Base Subcontract phase, Duke Power will perform technical and regulatory work required to prepare the Nuclear Reactors to use MOX fuel and will receive cost reimbursement plus a fixed fee. The first option phase provides for modification to the Nuclear Reactors as well as additional technical and regulatory work, and provides for Duke Power to receive cost reimbursement plus a fee. The second

option phase provides for Duke Power to purchase from DCSMOX fuel produced at the MOX FFF for use in the Nuclear Reactors, at discounts to prices of equivalent uranium fuel, over a 15-year period starting upon completion of the first option phase. As of June 30, 2003, DCS’ performance obligations under the Duke Power Subcontract include only the Base Subcontract phase, since DCS has not yet exercised its option to extend the term of performance under the Duke Power Subcontract to the first option phase, and DCS and Duke Power have not yet agreed on all open terms and conditions applicable to that phase.

The cost reimbursement nature of DCS’ commitment under the Prime Contract and the Duke Power Subcontract limits the exposure of DCS. Credit risk to DCS is limited in that the Prime Contract is with the DOE, a U.S. governmental entity. DCS is under no obligation to perform any contract work under the Prime Contract before funds have been appropriated from the U.S. Congress.

The Company is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee and the Duke Power Guarantee due to the uncertainty of whether: the DOE will exercise its options under the Prime Contract; 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; and the U.S. Congress will authorize funding for DCS’ work under the Prime Contract. Any liability of DPSG under the DOE Guarantee or the Duke Power Guarantee is directly related to and limited by the terms and conditions contained in the Prime Contract and the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Prime Contract, respectively. DPSG also has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee or the Duke Power Guarantee in excess of its proportional ownership percentage of DCS.

As of June 30, 2003, the Company had no liabilities recorded on its Consolidated Balance Sheet for the above mentioned MOX guarantees.

Other Guarantees and Indemnifications. The Company 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 the Company could have been required to make under these performance guarantees as of June 30, 2003 was approximately $2.8 billion. Of this amount, approximately $2.3 billion relates to guarantees of the payment and performance of affiliated entities, such as Duke Energy Fuels and DEM and approximately $200 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $10 million of the performance guarantees expire in 2003 approximately $60 million expire in 2004, and approximately $100 million expire in 2005, with the remaining performance guarantees having no contractual expiration. Additionally, the Company has issued joint and several guarantees to certain of the D/FD project owners, which guarantee 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 the Company 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 D/FD partners is responsible for 50% of any payments to be made under these guarantee contracts.

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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. These performance guarantees require Westcoast to make payment to the guaranteed third party upon the failure of the unconsolidated entity to make payment under certain 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 these performance guarantees as of June 30, 2003 was approximately $75 million. Of these guarantees, approximately $16 million expire from 2004 to 2007, with the remainder expiring after 2007 or having no contractual expiration.

Stand-by letters of credit are conditional commitments issued by banks to guarantee the performance of non-wholly owned entities to a third party or customer. Under these agreements, the Company has payment obligations which are triggered by the failure of a non-wholly owned entity to make payment to a third party or customer, according to the terms of the underlying contract and the subsequent draw by the third party or customer under the letter of credit. These letters of credit expire in various amounts between 2003 and 2004. The maximum potential amount of future payments the Company could have been required to make under these letters of credit as of June 30, 2003 was approximately $500 million. Of this amount, approximately $400 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities, and approximately $25 million relates to affiliated entities, such as DEM. Related to these letters of credit, the Company has received collateral from non-wholly owned consolidated entities in the amount of approximately $370 million as of June 30, 2003.

The Company has guaranteed the issuance 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, 2003, the Company had guaranteed approximately $110 million of outstanding surety bonds related to obligations of non-wholly owned entities. Of this amount, approximately $20 million relates to affiliated entities, such as DEM. These bonds expire in various amounts, primarily between 2003 and 2004. Of this amount, approximately $10 million relates to obligations of less than wholly owned consolidated entities.

Field Services and Natural Gas Transmission have issued certain guarantees of debt associated with non-consolidated entities and less than wholly-owned entities, respectively. In the event that non-consolidated entities or less than wholly-owned entities default on the debt payments, Field Services or Natural Gas Transmission would be required to perform under the guarantees and make payment on the outstanding debt balance of the non-consolidated entity. As of June 30, 2003, Field Services was the guarantor of approximately $100 million of debt associated with non-consolidated entities. Natural Gas Transmission was the guarantor of approximately $10 million of debt associated with less than wholly-owned entities (including $5 million related to Westcoast). These guarantees principally expire in 2003 for Field Services and 2019 for Natural Gas Transmission.

The Company has certain guarantees issued to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned 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 goods and services provided. In connection with the sale of DE&S, the Company has received back-to-back indemnification from the buyer indemnifying the Company for any amounts paid by the Company related to the DE&S guarantees. In connection with the sale of DukeSolutions, the Company received indemnification from the buyer for the first $2.5 million paid by the Company related to the DukeSolutions guarantees. Additionally, for certain performance guarantees, the Company has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2003 to 2019, with others having no specific term. The Company is unable to estimate the total maximum potential amount of future payments under these guarantees since most of the underlying guaranteed agreements contain no limits on potential liability.

The Company 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 indemnification

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agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The Company’s maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The Company 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 under these indemnities.

As of June 30, 2003, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial.

12. Subsequent Events

On July 9, 2003, the Company and Fluor Corporation announced that the D/FD partnership between subsidiaries of the two companies will be dissolved, at the request of Fluor Corporation. The partners of D/FD have adopted a plan for the orderly wind-down of the business of D/FD over the next two years. Many details of the dissolution of the partnership remain to be developed. The Company is still assessing the impact of this event but anticipates that the dissolution of this partnership will not have a material effect on its consolidated results of operations, cash flows or financial position.

In connection with the Company’s continued focus on non-strategic asset sales, on July 24, 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $300 million, including $222 million in project debt, to Freeport-McMoRan Copper & Gold Inc. The $222 million of project debt included in the transaction represents the Company’s share of total project debt of $259 million, which remains with PJP. The sale will result in a reduction to the Company’s consolidated indebtedness of $259 million.

On August 12, 2003, the Company announced that it has entered into an agreement to sell 25% undivided interest in the Duke Energy Vermillion facility for approximately $44 million. The Company expects to record a loss on the sale of approximately $19 million during the third quarter of 2003. The Company will continue to own the remaining 75% interest in the facility. The sale is subject to regulatory approval but is expected to close by the second quarter of 2004.

For information on subsequent events related to regulatory matters see Note 5, Notices of Proposed Rulemaking section. For information on subsequent events related to litigation and contingencies see Note 10, Litigation section. For information on subsequent events related to debt, credit facilities and other financing matters see Note 8.

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

INTRODUCTION

Duke Capital Corporation (collectively with its subsidiaries, the Company), is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as the parent of some of the Company’s non-utility and other operations. The Company provides financing and credit enhancement services for its subsidiaries and conducts operations through its business segments. See Note 1 to the Consolidated Financial Statements for descriptions of the Company’s business segments.

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

RESULTS OF OPERATIONS

Net Income

For the three months ended June 30, 2003, net income was $297 million, compared with net income of $239 million for the same period in 2002. The $58 million increase was due primarily to increased earnings before interest and taxes (EBIT) of $134 million (for a detailed discussion, see Consolidated EBIT below) offset by increased interest expense of $55 million and increased income tax expense of $24 million. Interest expense increased due primarily to decreased capitalized interest for Duke Energy North America (DENA). Income tax expense increased due primarily to increased earnings before income taxes. (For a detailed discussion of interest and taxes, see Other Impacts on Net Income.)

For the six months ended June 30, 2003, net income was $452 million, compared with net income of $413 million for the same period in 2002. The $39 million increase was due primarily to increased EBIT of $345 million (for a detailed discussion, see Consolidated EBIT below). Offsetting increased EBIT was increased interest expense of $193 million due primarily to higher debt balances primarily resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast Energy Inc. (Westcoast) and lower capitalized interest for DENA (for a detailed discussion, see Other Impacts on Net Income). Also contributing to the offset were charges related to changes in accounting principles of $52 million in 2003. Those changes included an after-tax and minority interest charge of $42 million related to the implementation of the 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 an after-tax charge of $10 million due to the implementation of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.”

All amounts discussed in the following Consolidated Operating Revenues, Consolidated Operating Expenses, Consolidated Operating Income and Consolidated EBIT sections are net of intercompany amounts that are eliminated in consolidation.

Consolidated Operating Revenues

Consolidated operating revenues for the three months ended June 30, 2003 increased $1,361 million to $3,760 million from $2,399 million for the same period in 2002. This change was driven by a $1,066 million increase in Sales of Natural Gas and Petroleum Products due primarily to an increase at Field Services related primarily to improved commodity pricing, and an increase at DENA and International Energy primarily due to the adoption of the final consensus on EITF Issue No. 02-03 on January 1, 2003 upon which the Company began to report revenues and expenses for certain derivative and nonderivative gas and other contracts on a gross basis instead of a net basis. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF Issue No. 02-03. Also contributing to increased revenues was a $262 million increase in trading and marketing net margin within Other Operating Revenues driven by sales of undesignated non-trading derivative contracts for physical gas being shown gross in 2003 and net in 2002. (See Note 2 to the Consolidated Financial Statements.)

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Consolidated operating revenues for the six months ended June 30, 2003 increased $3,577 million to $8,184 million from $4,607 million for the same period in 2002. The change was driven by a $3,461 million increase in Sales of Natural Gas and Petroleum Products due primarily to increases at Field Services, DENA, Natural Gas Transmission and International Energy. Sales at Field Services were driven by improved commodity pricing. Sales at Natural Gas Transmission were driven by two additional months of income from assets acquired or consolidated as part of the Westcoast acquisition. The increases at DENA and International Energy were driven by the adoption of the final consensus on EITF Issue No. 02-03, as discussed above.

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

Consolidated Operating Expenses

Changes in consolidated operating expenses for both the three months and six months ended June 30, 2003, as compared to the same periods in 2002, were driven by the same changes as consolidated operating revenues: increased commodity prices at Field Services and the adoption of the final consensus on EITF Issue No. 02-03.

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

Consolidated Operating Income

Operating income for the three months ended June 30, 2003 remained relatively flat, decreasing only $10 million to $489 million from $499 million for the same period in 2002.

For the six months ended June 30, 2003, operating income increased $209 million to $1,047 million from $838 million for the same period in 2002. The largest driver of the higher results was the two additional months of transportation, storage and distribution income from assets acquired or consolidated as part of the Westcoast acquisition.

Consolidated EBIT

Consolidated EBIT for the three months ended June 30, 2003 increased $134 million to $765 million from $631 million for the same period in 2002. The change was due primarily to increased commodity price impacts at Field Services, increased marketing margins in International Energy’s European operations and DENA’s gain on the sale of its 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel), offset by decreased energy generation revenues.

EBIT for the six months ended June 30, 2003 increased $345 million to $1,394 million from $1,049 million for the six months ended June 30, 2002. The increase resulted primarily from two additional months of transportation, storage and distribution income from assets acquired or consolidated as part of the Westcoast acquisition. Also contributing to the increase were increased commodity price impacts at Field Services; DENA’s gain on the sale of Ref-Fuel, offset by increased expenses; and increased EBIT at International Energy primarily attributable to improved marketing margins and decreased costs in Europe.

For a more detailed discussion of EBIT, see segment discussions below.

Consolidated EBIT is viewed as a non-Generally Accepted Accounting Principles (GAAP) measure under the rules of the Securities and Exchange Commission (SEC). The Company has included EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance. On a segment basis, EBIT represents all profits (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash and cash equivalents are managed centrally by the Company. Since the business units do not manage those items, the gains and losses on foreign currency remeasurement associated with cash balances and third-party

31

interest income on those balances are generally excluded from the segments’ EBIT. Management considers EBIT to be a good indicator of each segment’s operating performance, as it represents the results of the Company’s ownership interests in operations without regard to financing methods or capital structures.

On a consolidated basis, EBIT is also used as one of the measures to assess performance and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Income. The use of EBIT as one of the performance measures on a consolidated basis follows the use of EBIT for assessing segment performance, and the Company believes EBIT is used by its investors as a supplemental financial measure in the evaluation of the Company’s consolidated results of operations.

The following table shows the components of consolidated EBIT and reconciles consolidated operating income and EBIT to net income.

Reconciliation of Operating Income to Net Income(in millions)
	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003			2002
Operating income	$	489	$	499	$	1,047		$	838
Other income and expensesa		276		132		347			211
EBIT		765		631		1,394			1,049
Interest expense		272		217		550			357
Minority interest expense		49		52		90			73
Earnings before income taxes		444		362		754			619
Income taxes		147		123		250			206
Income before cumulative effect of change in accounting principles		297		239		504			413
Cumulative effect of change in accounting principles, net of tax and minority interest		—		—		(52	)		—
Net income	$	297	$	239	$	452		$	413

^a Includes gains on sale of equity investments

EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. The Company’s EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

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Business segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment(in millions)
	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003		2002
Natural Gas Transmission	$	306		$	313		$	729	$	579
Field Services		76			41			109		76
Duke Energy North America		204			124			225		170
International Energy		111			57			165		114
Total reportable segment EBIT		697			535			1,228		939
Other Operations		27			102			47		106
Othera		(15	)		(68	)		19		(117	)
Total reportable segment and other EBIT		709			569			1,294		928
EBIT attributable to:
Minority interests		46			42			92		56
Third-party interest income		2			12			5		48
Foreign currency remeasurement gain		8			8			3		17
Consolidated EBIT	$	765		$	631		$	1,394	$	1,049

^a Other primarily includes certain unallocated corporate costs and elimination of intersegment profits.

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

Natural Gas Transmission

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions, except where noted)	2003		2002		2003		2002
Operating revenues	$	692	$	621	$	1,660	$	1,071
Operating expenses		421		361		988		579
Gains on sales of other assets, net		—		—		1		—
Operating income		271		260		673		492
Other income, net of expenses		45		62		79		99
Minority interest expense		10		9		23		12
EBIT	$	306	$	313	$	729	$	579
Proportional throughput, TBtua		742		702		1,824		1,372

^a Trillion British thermal units

Three Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the three months ended June 30, 2003 increased $71 million to $692 million from $621 million for the same period in 2002. This increase resulted primarily from $41 million of favorable foreign exchange impacts on revenues from the Canadian operations due to the strengthening Canadian dollar. Additionally, revenues increased due to business expansion projects in the U.S. and increased due to commodity costs of natural gas of approximately $31 million that are passed through without a mark-up to customers at Union Gas Limited (Union Gas), the natural gas distribution operations in Ontario, Canada.

Operating Expenses. Operating expenses for the three months ended June 30, 2003 increased $60 million to $421 million from $361 million for the same period in 2002. This increase was due primarily to the foreign

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exchange impact on the Canadian operating expenses of $32 million and approximately $31 million in increased expenses related to increased natural gas prices at Union Gas.

Other Income, Net of Expenses. Other income, net of expenses decreased $17 million for the three months ended June 30, 2003, compared to the same period in 2002. A gain of $31 million was recognized on the sale of Natural Gas Transmission‘s investment in the Alliance Pipeline and the associated Aux Sable liquids plant in April 2003. This gain was partially offset by lower equity investment earnings in the second quarter of 2003 associated with those facilities and a $27 million construction fee from an affiliate in the second quarter of 2002 related to the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), an interstate natural gas pipeline of which Natural Gas Transmission owns 50%. Foreign exchange also negatively impacted other income due to the settlement of hedges related to foreign currency exposure.

EBIT. For the three months ended June 30, 2003, EBIT decreased $7 million, compared to the same period in 2002. As discussed above, this decrease resulted primarily from gains on sales of equity investments in 2003, net of lower equity earnings from those investments, offset by the construction fee from an affiliate related to the successful completion of Gulfstream in 2002 and business expansion projects.

Six Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the six months ended June 30, 2003 increased $589 million to $1,660 million from $1,071 million for the same period in 2002. This increase resulted primarily from January and February 2003 transportation, storage and distribution revenue of $466 million from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002. As a result of the strengthening Canadian dollar, foreign exchange favorably impacted revenues from the Canadian operations by $49 million. Additionally, revenues increased $18 million due to business expansion projects in the U.S., and increased due to commodity costs of natural gas of approximately $31 million that are passed through without a mark-up to customers at Union Gas.

Operating Expenses.Operating expenses for the six months ended June 30, 2003 increased $409 million to $988 million from $579 million for the same period in 2002. This increase was due primarily to incremental operating expenses of $319 million related to January and February 2003 operations of the gas transmission, storage and distribution assets acquired or consolidated in the Westcoast acquisition in March 2002. The increase in expenses was also caused by foreign exchange impacts of $35 million and approximately $31 million in increased expenses related to increased natural gas prices at Union Gas.

For the six months ended June 30, 2003, Natural Gas Transmission’s operating expenses increased approximately 71% when compared to the same period in 2002, while operating revenues increased approximately 55%. 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 Company’s natural gas transmission business prior to the acquisition of the Westcoast assets. 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).

Other Income, Net of Expenses.Other income, net of expenses decreased $20 million for the six months ended June 30, 2003, compared to the same period in 2002. A gain of $31 million was recognized on the sale of Natural Gas Transmission‘s investment in the Alliance Pipeline and the associated Aux Sable liquids plant in April 2003. This gain was offset by lower equity investment earnings associated with these facilities and a $27 million construction fee from an affiliate related to the successful completion of the Gulfstream project in the second quarter of 2002. The 2003 and 2002 six-month periods both include gains of $14 million from the sales of Natural Gas Transmission’s limited partnership interests in Northern Borders Partners L.P. Foreign exchange also negatively impacted other income by $11 million in 2003 due to the settlement of hedges related to foreign currency exposure.

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Minority Interest Expense. Minority interest expense increased $11 million for the six months ended June 30, 2003, compared to the same period in 2002. This was due to recognizing a full six months of minority interest expense in 2003, versus only four months during the first six months of 2002, from less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast.

EBIT. For the six months ended June 30, 2003, EBIT increased $150 million when compared to the same period in 2002 due primarily to business expansion projects in the U.S and incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast.

Field Services

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions, except where noted)	2003		2002		2003		2002
Operating revenues	$	1,924	$	1,376	$	4,377	$	2,510
Operating expenses		1,861		1,333		4,268		2,432
Gains on sales of other assets, net		26		—		26		—
Operating income		89		43		135		78
Other income, net of expenses		24		11		39		19
Minority interest expense		37		13		65		21
EBIT	$	76	$	41	$	109	$	76
Natural gas gathered and processed/transported, TBtu/da		7.9		8.4		7.9		8.4
Natural gas liquid (NGL) production, MBbl/db		361.5		392.0		368.3		390.4
Average natural gas price per MMBtuc	$	5.41	$	3.40	$	6.00	$	2.86
Average NGL price per gallond	$	0.49	$	0.37	$	0.54	$	0.34

^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

Three Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the three months ended June 30, 2003 increased $548 million to $1,924 million from $1,376 million for the same period in 2002. The increase was primarily driven by an approximate $522 million increase in sales of natural gas, NGLs and other petroleum products. These increases were mainly driven by a $0.12 per gallon increase in average NGL prices and a $2.01 per MMBtu increase in natural gas prices, offset by results of related hedging activity.

Operating Expenses.Operating expenses for the three months ended June 30, 2003 increased $528 million to $1,861 million from $1,333 million for the same period in 2002. The increase was due primarily to approximately $507 million in increased expenses related to purchases of natural gas, NGLs and other petroleum products. The increase in purchases was mainly driven by a $0.12 per gallon increase in average NGL prices, and a $2.01 per MMBtu increase in natural gas prices. Partially offsetting the commodity price increases were charges of approximately $18 million during the second quarter of 2002 for reserves for gas imbalances with suppliers and customers, and storage inventory writedowns.

Gains on Sales of Other Assets, Net. Gains on sales of other assets in 2003 related to the sale of one package of assets to Crosstex Energy Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy, LLC (ScissorTail). The assets sold to Crosstex consisted of the AIM Pipeline System in Mississippi; a 12.4% interest in the Seminole gas processing plant in Texas; the Conroe gas plant and gathering system in Texas; the Black Warrior pipeline system in Alabama; and two smaller systems –

35

Aurora Centana and Cadeville in Louisiana. The assets sold to ScissorTail consisted of various gas processing plants and gathering pipeline in eastern Oklahoma.

Other Income, Net of Expenses.Other income, net of expenses increased $13 million for the three months ended June 30, 2003, compared to the same period in 2002, due primarily to an $11 million gain on the sale of Class B units of TEPPCO Partners, L.P. (TEPPCO). TEPPCO is a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil, gathers and processes natural gas, and fractionates and transports NGLs.

Minority Interest Expense. Minority interest expense for the three months ended June 30, 2003 increased $24 million, compared to the same period in 2002, due to increased earnings from Duke Energy Field Services, LLC (DEFS), the Company‘s joint venture with ConocoPhillips. 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 Company‘s corporate level that are not included in DEFS.

EBIT.The increase in EBIT of $35 million was largely the result of higher NGL prices offset by higher natural gas prices and related hedging activity. Results for 2003 were positively impacted by the gain on sale of assets of $18 million (net of minority interest expense) and the $11 million gain on the sale of the TEPPCO units. In the second quarter of 2002, results were negatively impacted by $13 million (net of minority interest expense) due to increased reserves primarily related to imbalances with customers and suppliers and a storage inventory write-down charge.

Six Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the six months ended June 30, 2003 increased $1,867 million to $4,377 million from $2,510 million for the same period in 2002. The increase was primarily driven by an approximate $1,932 million increase on the sale of natural gas, NGLs and other petroleum products. These increases were mainly driven by a $0.20 per gallon increase in average NGL prices and a $3.14 per MMBtu increase in natural gas prices, offset by related hedging activity. These increases were partially offset by lower trading and marketing net margin of $44 million, due primarily to declines in natural gas and NGL trading. Offsetting the decrease in trading and marketing net margin was an increase of approximately $23 million related to physical natural gas asset based marketing activity which, prior to January 1, 2003, was recorded in trading and marketing net margin within Other Operating Revenues but is now presented on a gross basis in revenues and expenses in accordance with the final provisions of EITF Issue No. 02-03.

Operating Expenses.Operating expenses for the six months ended June 30, 2003 increased $1,836 million to $4,268 million from $2,432 million for the same period in 2002. The increase was due primarily to an approximately $1,816 million increase in expenses related to purchases of natural gas, NGLs and other petroleum products. The increase in purchases was mainly driven by a $0.20 per gallon increase in average NGL prices, and a $3.14 per MMBtu increase in natural gas prices. Also contributing to the increase in expenses were higher operating, maintenance, corporate overhead and depreciation costs of approximately $33 million due primarily to increased maintenance, repairs and capital expenditures. Slightly offsetting theses increases were charges of approximately $18 million during the second quarter of 2002, as mentioned above.

Gains on Sales of Other Assets, Net. Gains on sales of other assets all occurred in the second quarter of 2003, as discussed above.

Other Income, Net of Expenses.Other income, net of expenses increased $20 million for the six months ended June 30, 2003, compared to the same period in 2002, due primarily to an $11 million gain on the sale of Class B units of TEPPCO, as described above.

Minority Interest Expense. Minority interest expense increased $44 million for the six months ended June 30, 2003, compared to the same period in 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

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Services segment includes the results of incremental hedging activities contracted at the Company‘s corporate level that are not included in DEFS.

EBIT.The increase in EBIT of $33 million was largely the result of higher NGL prices being substantially offset by higher natural gas prices, related hedging activity, decreased trading and marketing net margin and increased operating expenses, as discussed above. Results for 2003 were positively impacted by the gain on sale of assets of $18 million (net of minority interest expense) and the $11 million gain on the sale of the TEPPCO units. The 2002 results were negatively impacted by $13 million (net of minority interest expense) due to increased reserves primarily related to imbalances with customers and suppliers and a storage inventory write-down charge.

Duke Energy North America

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions, except where noted)	2003			2002		2003			2002
Operating revenues	$	784		$	329	$	2,005		$	585
Operating expenses		774			212		1,983			418
Operating income		10			117		22			167
Other income, net of expenses		187			21		196			16
Minority interest (benefit) expense		(7	)		14		(7	)		13
EBIT	$	204		$	124	$	225		$	170
Actual plant production, GWha,b		4,510			5,377		9,620			9,526
Proportional megawatt capacity in operation							15,206			12,671

^a Gigawatt-hours

^b Includes plant production from plants accounted for under the equity method

Three Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the three months ended June 30, 2003 increased $455 million to $784 million from $329 million for the same period in 2002. Revenues increased $495 million in connection with the implementation of the remaining provisions of EITF Issue No. 02-03. As a result of adopting EITF Issue No. 02-03 on January 1, 2003, gains and losses for certain derivative and non-derivative contracts that were previously reported on a net basis in trading and marketing net margin within Other Operating Revenues under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Management Activities,” are now reported on a gross basis. Specifically, the $495 million increase was primarily related to the presentation effective on January 1, 2003, of certain derivative contracts related to DENA’s wholesale natural gas marketing operations and the presentation of gains and losses from the settlement of many non-derivative contracts on a gross basis in the Consolidated Statements of Income. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF issues. The increase related to EITF Issue No. 02-03 was partially offset by a decrease of $78 million in energy generation revenues, due to an $85 million decrease from overall lower power prices offset by a slight increase in power volumes. Also contributing to increased revenues was a $14 million reduction in the prior year of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques to all North American regions in the second quarter of 2002.

Operating Expenses.Operating expenses for the three months ended June 30, 2003 increased $562 million to $774 million from $212 million for the same period in 2002. Similar to the increase in operating revenues discussed above, operating expenses increased $540 million due to the adoption of the final

37

consensus on EITF Issue No. 02-03. Also contributing to the increase in operating expenses was increased energy generation operating, maintenance and depreciation expense of $29 million due to a full three months of operations in 2003 for projects that entered into commercial operations during or after the second quarter of 2002. This increase was offset by a $54 million decrease in the cost of fuel used in electric

generation resulting from lower gas cost net of hedging activity. General and administrative costs increased $35 million due primarily to the release of incentive accruals in the second quarter of 2002.

Other Income, Net of Expenses.Other income, net of expenses increased $166 million for the three months ended June 30, 2003, compared to the same period in 2002. The increase was due primarily to the sale of DENA’s 50% ownership interest in Ref-Fuel to Highstar Renewable Fuels LLC for a gain of approximately $175 million in 2003, slightly offset by lower equity earnings from the investment.

Minority Interest (Benefit) Expense.For the three months ended June 30, 2003, losses at Duke Energy Trading and Marketing, LLC (DETM, the Company’s 60/40 joint venture with ExxonMobil Corporation) resulted in a minority interest benefit, whereas earnings at DETM for the prior year resulted in minority interest expense. DETM’s lower results were due to a reduction in mark-to-market earnings.

EBIT. For the three months ended June 30, 2003, EBIT increased $80 million, compared to the same period in 2002. The increase was driven by the factors discussed above, primarily the gain on the sale of Ref-Fuel, offset by decreased energy generation revenues and increased depreciation expenses.

Six Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the six months ended June 30, 2003 increased $1,420 million to $2,005 million from $585 million for the same period in 2002. Revenues increased $1,375 million due to the adoption of EITF Issue No. 02-03, as discussed above. In addition, energy generation revenues increased $7 million as a result of a $51 million increase due to higher volumes, offset by a $44 million decrease due to lower prices. Also contributing to increased revenues was a $14 million reduction in the prior year of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques to all North American regions in the second quarter of 2002.

Operating Expenses.Operating expenses for the six months ended June 30, 2003 increased $1,565 million to $1,983 million from $418 million for the same period in 2002. Similar to the increase in operating revenues described above, operating expenses increased $1,409 million due to the adoption of the final consensus on EITF Issue No. 02-03. Also contributing to the increase in operating expenses was increased energy generation operating, maintenance and depreciation expense of $60 million due to a full six months of operations in 2003 for projects that entered into commercial operations during 2002. General and administrative costs increased $89 million due primarily to the release of incentive accruals in 2002.

Other Income, Net of Expenses.Other income, net of expenses increased $180 million for the six months ended June 30, 2003, compared to the same period in 2002. The increase was due primarily to the sale of DENA’s 50% ownership interest in Ref-Fuel to Highstar Renewable Fuels LLC for a gain of approximately $175 million in 2003. Also contributing to the increase was higher equity earnings from Ref-Fuel during the six months ended June 30, 2003 as compared to the same period in 2002.

Minority Interest (Benefit) Expense.For the six months ended June 30, 2003, losses at DETM resulted in a minority interest benefit, whereas earnings at DETM for the prior year resulted in minority interest expense. DETM’s lower results were due to a reduction in mark-to-market earnings.

EBIT. For the six months ended June 30, 2003, EBIT increased $55 million, compared to the same period in 2002, due to the factors discussed above, primarily the gain on the sale of Ref-Fuel, offset by increased expenses.

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International Energy

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions, except where noted)	2003		2002		2003		2002
Operating revenues	$	366	$	219	$	748	$	508
Operating expenses		266		179		597		414
Operating income		100		40		151		94
Other income, net of expenses		16		23		24		31
Minority interest expense		5		6		10		11
EBIT	$	111	$	57	$	165	$	114
Sales, GWh		5,318		5,014		10,077		9,946
Proportional megawatt capacity in operation						4,887		4,971
Proportional maximum pipeline capacity in operation, MMcf/da						363		363

^a Million cubic feet per day

Three Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues. Operating revenues for the three months ended June 30, 2003 increased $147 million to $366 million from $219 million for the same period in 2002. Of this increase, $155 million was due to the adoption of the final consensus on EITF Issue No. 02-03, whereby International Energy began to recognize certain natural gas transactions that were previously reported on a net basis on a gross basis in 2003. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF issues. Also contributing to the increase was an $11 million adjustment to revenues and receivables during the second quarter 2003 as a result of a regulatory audit in Brazil. These increases were partially offset by $11 million due to changes in 2003 in the timing of revenue recognition and $11 million due to lower natural gas sales volumes due to the early termination of a natural gas sales contract.

Operating Expenses. Operating expenses for the three months ended June 30, 2003 increased $87 million to $266 million from $179 million for the same period in 2002. Similar to the increase in operating revenues described above, operating expenses increased $121 million due to the adoption of the final consensus on EITF Issue No. 02-03. Increased operating expenses were partially offset by $30 million due to lower natural gas purchases and a reduction in estimated probable losses within this line of business due to the early termination of a natural gas sales contract, and an $8 million decrease in expenses and payables from the regulatory audit in Brazil.

EBIT. For the three months ended June 30, 2003, EBIT increased $54 million, compared to the same period in 2002. The increase was attributable to improved marketing margins and decreased costs in Europe of $28 million, a $19 million adjustment from the regulatory audit in Brazil and $18 million due to a decrease in liquefied natural gas (LNG) activity and a reduction in estimated losses within this line of business due to the early termination of a natural gas sales contract. These increases in EBIT were partially offset by $10 million from the change in values of currencies, primarily related to International Energy’s investments in Mexico and Brazil.

Six Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues. Operating revenues for the six months ended June 30, 2003 increased $240 million to $748 million from $508 million for the same period in 2002. Of this increase, $303 million was due to the adoption of EITF Issue No. 02-03, as discussed above. Also contributing to the increase were revenues of $24 million from assets acquired in France during the third quarter of 2002, $13 million from increased

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energy prices and $9 million from increased generation at International Energy’s Latin American operations, and an $11 million adjustment to revenues and receivables during the second quarter 2003 as a result of a regulatory audit in Brazil. These increases were partially offset by a $91 million increase in 2002 revenues related to final guidance on accounting from Brazilian regulatory authorities for electricity rationing, a $20 million decrease from currency devaluations within Brazil and Argentina, and $23 million due to changes in the timing of revenue recognition in 2003.

Operating Expenses. Operating expenses for the six months ended June 30, 2003 increased $183 million to $597 million from $414 million for the same period in 2002. Similar to the increase in operating revenues described above, operating expenses increased $269 million due to the adoption of the final consensus on EITF Issue No. 02-03. Additionally, operating expenses increased $20 million from assets acquired in France during the third quarter of 2002 and $4 million from increased prices and $7 million from increased generation within International Energy’s Latin American operations. These increased operating expenses were partially offset by a $91 million increase in 2002 expenses related to final guidance on accounting from Brazilian regulatory authorities for electricity rationing, $12 million due to lower natural gas purchases and a reduction in estimated probable losses within this line of business due to the early termination of a natural gas sales contract, and an $8 million decrease in expenses and payables from the regulatory audit in Brazil.

EBIT. For the six months ended June 30, 2003, EBIT increased $51 million, compared to the same period in 2002. The increase was primarily attributable to improved marketing margins and decreased costs in Europe of $23 million, a $19 million adjustment from the regulatory audit in Brazil, $18 million due to a decrease in LNG activity and a reduction in estimated losses within this line of business due to the early termination of a natural gas sales contract. EBIT also increased due to $20 million in cost reduction efforts and $12 million in increased equity earnings related to International Energy’s investment in National Methanol Company, which was driven by favorable product prices. These increases in EBIT were partially offset by a $16 million decrease from currency valuations and a $26 million decrease related to the timing of revenue recognition, of which $11 million relates to a charge related to the timing of revenue recognition at the Cantarell equity investment in Mexico, a nitrogen-production plant which was acquired with Westcoast.

Other Operations

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2003		2002		2003		2002
Operating revenues	$	178	$	148	$	259	$	311
Operating expenses		162		108		242		265
Gains on sales of other assets, net		—		16		—		1
Operating income		16		56		17		47
Other income, net of expenses		12		46		31		58
Minority interest expense (benefit)		1		—		1		(1	)
EBIT	$	27	$	102	$	47	$	106

Three Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the three months ended June 30, 2003 increased $30 million to $178 million from $148 million for the same period in 2002. The increase was due primarily to increased revenues at Crescent Resources, LLC (Crescent) of $49 million due primarily to revenues from a multifamily project sale in June 2003 and an increase in revenues from lot sales; and increased revenues at Energy Delivery Services (EDS) of $19 million as a result of EDS beginning operations in May of 2002 and thus not recognizing a full quarter of operations in the prior year. Offsetting the increases in revenues was the sale of DE&S and DukeSolutions in 2002, which contributed $36 million to revenues during the second quarter of 2002.

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Operating Expenses. Operating expenses for the three months ended June 30, 2003 increased $54 million to $162 million from $108 million for the same period in 2002. The increase in operating expenses was due primarily to increased expenses at Crescent of $51 million due primarily to the cost of a multifamily project sale and an increase in the cost of developed lots sold; increased expenses at EDS of $18 million as a result of EDS beginning operations in May of 2002 and thus not recognizing a full quarter of operations in the prior year; and a $14 million reserve in 2003 at Duke Capital Partners (DCP) to reflect a permanent reduction in the value of its loan portfolio. These increases were partially offset by the sale of Duke Engineering & Services, Inc. (DE&S) and Duke Solutions, Inc. (DukeSolutions) in 2002, which contributed $36 million to expenses during the second quarter of 2002.

Gains on Sales of Other Assets, Net. Gains on sales of other assets for the three months ended June 30, 2003 decreased $16 million, compared to the same period in 2002 due to net gains during the second quarter of 2002 of $16 million on the sale of DE&S and DukeSolutions.

Other Income, Net of Expenses.Other income, net of expenses decreased $34 million for the three months ended June 30, 2003, compared to the same period in 2002. The decrease was due primarily to decreased equity earnings related to Duke/Fluor Daniel (D/FD), a 50/50 partnership between subsidiaries of the Company and Fluor Corporation. In 2002, D/FD completed a number of energy plants, most of which were constructed for DENA and therefore the related intercompany profit was eliminated within the Other group.

EBIT. For the three months ended June 30, 2003, EBIT decreased $75 million, compared to the same period in 2002. As discussed above, the decline in EBIT was primarily driven by the decline in the D/FD business, a decrease in the gain on sale of assets and the 2003 reserve at DCP.

Six Months Ended June 30, 2003 as Compared to June 30, 2002

Operating Revenues.Operating revenues for the six months ended June 30, 2003 decreased $52 million to $259 million from $311 million for the same period in 2002. The decrease was due primarily to the sale of DE&S and DukeSolutions in 2002, which contributed $162 million to revenues during the first six months of 2002. Offsetting this decrease in revenues was increased revenues at Crescent of $49 million due primarily to revenues from a multifamily project sale in June 2003 and an increase in revenues from lot sales; and increased revenues at EDS of $50 million as a result of EDS beginning operations in May of 2002 and thus not recognizing a full six months of operations in the prior year.

Operating Expenses. Operating expenses for the six months ended June 30, 2003 decreased $23 million to $242 million from $265 million for the same period in 2002. The decrease in operating expenses was due primarily the sale of DE&S and DukeSolutions in 2002, which contributed $158 million to expenses during the first six months of 2002. Offsetting this decrease in expenses were increased expenses at Crescent of $51 million due primarily to the cost of a multifamily project sale and an increase in the cost of developed lots sold; increased expenses at EDS of $47 million as a result of EDS beginning operations in May of 2002 and thus not recognizing a full six months of operations in the prior year; and a $14 million reserve in 2003 at DCP to reflect a permanent reduction in the value of its loan portfolio.

Other Income, Net of Expenses.Other income, net of expenses decreased $27 million for the six months ended June 30, 2003, compared to the same period in 2002. The decrease was due primarily to decreased equity earnings related to D/FD. In 2002, D/FD completed a number of energy plants, most of which were constructed for DENA and therefore the related intercompany profit was eliminated within the Other group.

EBIT. For the six months ended June 30, 2003, EBIT decreased $59 million, compared to the same period in 2002. As discussed above, the decline in EBIT was primarily driven by the decline in the D/FD business and the 2003 reserve at DCP.

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Other

For the three months ended June 30, 2003, EBIT for Other improved $53 million to a loss of $15 million from a loss of $68 million for the same period in 2002. For the six months ended June 30, 2002, it improved $136 million to $19 million from a loss of $117 million for the same period in 2002. The increases were due primarily to decreased intercompany profits between the Company’s segments which are eliminated within Other. These intercompany profits are primarily a result of earnings at D/FD for energy plants it has under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

Other Impacts on Net Income

Interest expense increased $55 million for the three months June 30, 2003, compared to the same period in 2002. The increase was due primarily to a decrease in capitalized interest for DENA resulting from significantly lower plant construction activity in 2003. In addition to increased outstanding debt and higher average interest rates as a result of reduced reliance on commercial paper programs.

For the six months ended June 30, 2002, interest expense increased $193 million, compared to the same period in 2002. The increase was due primarily to higher debt balances primarily resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast and lower capitalized interest for DENA. The remaining portion of the increase was due to higher average interest rates as a result of reduced reliance on commercial paper programs.

Minority interest expense decreased $3 million for the three months and increased $17 million for the six months ended June 30, 2003, compared to the same periods in 2002. Minority interest expense includes expense related to regular distributions on preferred securities of the Company and its subsidiaries, which decreased $7 million for the three months and $15 million for the six months ended June 30, 2003, as compared to the same periods in 2002. The decreases were due primarily to lower distributions related to Catawba River Associates, LLC. Beginning in October 2002 due to changes in the entity’s ownership structure, costs associated with this financing have been classified as interest expense.

Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of the Company’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 $4 million for the three months and $32 million for the six months ended June 30, 2003, as compared to the same periods for 2002. The 2003 increases were driven by increased earnings from DEFS and from recognizing a full six months of minority interest expense in 2003, versus only three months during 2002, from less than wholly owned subsidiaries acquired in the March 2002 acquisition of Westcoast. These increases were partially offset by decreased earnings at DETM.

During the first quarter of 2003, the Company recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $52 million as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $42 million related to the implementation of EITF Issue No. 02-03 (see Note 2 to the Consolidated Financial Statements) and an after-tax charge of $10 million due to the implementation of SFAS No. 143, (see Note 2 to the Consolidated Financial Statements).

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LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2003, the Company had $1,452 million in cash and cash equivalents compared to $814 million as of December 31, 2002. The Company’s working capital was a $639 million surplus as of June 30, 2003, compared to a $237 million deficit as of December 31, 2002. The Company relies upon cash flows from operations, as well as borrowings and the sale of assets to fund its liquidity and capital requirements. A material adverse change in operations or available financing may impact the Company’s ability to fund its current liquidity and capital resource requirements.

In addition to the risk associated with the market fluctuation in the price of natural gas, electricity and other energy-related products marketed and purchased, the Company is exposed to the risk of loss resulting from non-performance of contractual obligations by a counterparty. During 2003, certain counterparties who have contractual arrangements with the Company have either encountered financial difficulty or declared bankruptcy. The Company has taken active measures, such as the modification of collateral agreements and modification of existing contracts, to mitigate the risks associated with such counterparties and as of June 30, 2003, has not realized material losses from non-performance of such counterparties. While the Company has processes in place to monitor and attempt to mitigate economic exposures to these counterparties, the energy sector remains financially distressed.

For additional information, see Credit Risks in Note 7 to the Consolidated Financial Statements.

Operating Cash Flows

Net cash provided by operations decreased $19 million for the six months ended June 30, 2003 when compared to the same period in 2002. The decrease in cash provided by operating activities was due primarily to unfavorable changes in working capital compared to 2002, which was principally due to a reduction in trade accounts payable. The decrease in cash provided by operating activities was also driven by changes in net realized and unrealized mark-to-market and hedging transactions and gains on sale of equity investments and other assets.

Investing Cash Flows

Cash flows from investing activities changed $4,171 million to net cash provided by investing activities of $253 million for the six months ended June 30, 2003 from net cash used in investing activities of $3,918 million for the six months ended June 30, 2002. Capital and investment expenditures decreased $3,486 million for the six months ended June 30, 2003 when compared to the same period in 2002. Decreased capital expenditures were due primarily to the 2002 acquisition of Westcoast for $1,707 million in cash, net of cash acquired, a decrease in DENA’s investments in generating facilities, and a decrease in investments in property, plant and equipment at Field Services and International Energy. Investment activities also changed in 2003 compared to 2002, due primarily to reduced investments at Other Operations (primarily related to DCP) and Natural Gas Transmission’s investment in a 50% interest in Gulfstream. Increased proceeds of $1,026 million from sales of equity investments and other assets also contributed to the change in net cash used in investing activities. The increased proceeds in 2003 were primarily due to the sale of DENA’s 50% ownership interest in Ref-Fuel, as well as the sale of Natural Gas Transmission’s wholly owned Empire State Pipeline and its investment in the Alliance Pipeline and the associated Aux Sable liquids plant.

Financing Cash Flows and Liquidity

Cash flows from financing activities changed $3,305 million to net cash used in financing activities of $848 million for the six months ended June 30, 2003 from net cash provided by financing activities of $2,457 million for the six months ended June 30, 2002. This change is due primarily to the net reduction of outstanding long-term debt, of guaranteed preferred beneficial interests in subordinated notes and of notes payable and commercial paper during the first six months of 2003 as compared to the same period in 2002 when the Company acquired Westcoast and financed other business expansion projects.

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The Company’s cash requirements for 2003 are expected to be funded by cash from operations and the sale of assets, and to be adequate for funding capital expenditures and repaying approximately $2,900 million of debt and trust preferred securities in 2003. During the first seven months of 2003, the Company announced or completed asset sales of approximately $1,600 million in gross proceeds, including $58 million of debt related to the sale of Empire State Pipeline and $222 million of proportional project debt related to the sale of P.T. Puncakjaya Power (PJP). In addition, the Company may access the capital markets depending on market opportunities and other factors. The Company does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee contracts. For additional information on these commitments, see Notes 10 and 11 to the Consolidated Financial Statements and the Commercial Commitments table in “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Liquidity and Capital Resources—Contractual Obligations and Commercial Commitments” in the Company’s Form 10-K/A for December 31, 2002. Management believes the Company has adequate financial flexibility and resources to meet its future needs.

Credit Ratings. In March 2003, Moody’s Investor Service (Moody’s) placed its long-term and short-term ratings of the Company and DEFS, and its long-term ratings of Texas Eastern Transmission, LP (Texas Eastern) and PanEnergy Corp (PanEnergy), on Review for Potential Downgrade. In June 2003, Moody’s lowered its long-term and short-term ratings of the Company, and its long-term ratings of Texas Eastern and PanEnergy one ratings level. Moody’s actions were prompted by concerns regarding leverage ratios and cash flow coverage metrics at the Company, and uncertainties associated with cash flow contributions from DENA and Duke Energy International, LLC. Moody’s concluded its actions by placing the Company, Texas Eastern and PanEnergy on Stable Outlook. Moody’s continues to have DEFS on Review for Potential Downgrade. Moody’s review of DEFS was prompted by perceived pressures on DEFS’ debt coverage ability.

In June 2003, Standard & Poor’s (S&P) lowered its long-term ratings of the Company and its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and DEFS) one ratings level. In addition, S&P lowered its short-term ratings of Westcoast and Union Gas. S&P’s actions were based on concern about the Company’s ability to strengthen its financial profile during the remainder of 2003 and in 2004, and its ability to absorb any further weakening in operating cash flows, while still meeting its debt reduction targets. S&P concluded its actions by leaving the Company and its subsidiaries, excluding M&N Pipeline and DEFS, on Negative Outlook.

The following table summarizes the credit ratings of the Company, its principal funding subsidiaries and its trading and marketing subsidiary DETM as of June 30, 2003.

Credit Ratings Summary as of June 30, 2003
	Standard and Poors	Moody’s Investor Service	Fitch Ratings	Dominion Bond Rating Service
Duke Capital Corporationa	BBB	Baa3	BBB	Not applicable
Duke Energy Field Servicesa	BBB	Baa2	BBB	Not applicable
Texas Eastern Transmission, LPa	BBB+	Baa2	BBB+	Not applicable
Westcoast Energy Inc.a	BBB+	Not applicable	Not applicable	A(low)
Union Gas Limiteda	BBB+	Not applicable	Not applicable	A
Maritimes & Northeast Pipeline, LLCb	A	A1	Not applicable	Not applicable
Maritimes & Northeast Pipeline, LPb	A	A1	Not applicable	A
Duke Energy Trading and Marketing, LLCc	BBB-	Not applicable	Not applicable	Not applicable

^a Represents senior unsecured credit rating

^b Represents senior secured credit rating

^c Represents corporate credit rating

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The Company’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund the Company’s capital and investment expenditures, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors affecting the Company’s business, the Company is unable to execute its business plan or if its earnings outlook deteriorates, the Company’s ratings could be further affected.

The Company and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon the Company’s economic position at points in time during the life of a contract and the credit rating of the subsidiary obligated under the collateral agreement. DETM currently generates the majority of the Company’s collateral requirements.

A reduction in DETM’s credit rating to below investment grade at June 30, 2003 would have resulted in the posting of additional cash collateral of up to approximately $220 million by the Company.

If credit ratings for the Company 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 described above.

For a discussion of the Company’s significant financing activities, see Notes 8 and 9 to the Consolidated Financial Statements. For a discussion of the Company’s credit facilities and related borrowings and effective SEC and Canadian shelf registrations, see Note 8 to the Consolidated Financial Statements.

CURRENT ISSUES

For information on current issues related to the Company, see the following Notes to the Consolidated Financial Statements: Note 5, Regulatory Matters, and Note 10, Commitments and Contingencies.

New Accounting Standards

SFAS No. 146,“Accounting for Costs Associated with Exit or Disposal Activities.” In June 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 146 which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company has adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost was recognized on the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of recognizing future restructuring costs as well as the amounts recognized as liabilities.

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. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is currently assessing the impact of adoption of SFAS No. 149 on its Consolidated Financial Statements.

On June 25, 2003, the FASB cleared the guidance contained in DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue C20, which applies only to the guidance in paragraph 10(b) of

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FASB Statement No. 133 and not in reference to embedded derivatives, describes three circumstances in which the underlying in a price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” The guidance in DIG Issue C20 is effective for the Company on October 1, 2003. The Company is currently assessing DIG Issue C20 but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

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, such financial 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 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 must be applied to the Company’s existing financial instruments beginning on July 1, 2003. The Company anticipates that the adoption of this statement will not have a material effect on its consolidated results of operations, cash flows or financial position.

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. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company 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 46 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that the Company will disclose information about or consolidate one or more variable interest entities upon the application of FIN 46, primarily as the result of investments it has in certain unconsolidated affiliates. Any significant exposure to losses related to these entities would be related to guarantee obligations as discussed in Note 11 to the Consolidated Financial Statements. Additionally, see Note 9 to the Consolidated Financial Statements for a discussion of the impact of adoption of FIN 46 on the Company’s trust preferred securities. The Company continues to assess FIN 46 but does not anticipate that it will have a material impact on its 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 the relevant facts and circumstances. In analyzing the facts and circumstances, EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal vs. Net as an Agent,” and APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. Under the EITF’s consensus, transition for this issue would be for transactions or arrangements entered into by the Company after September 30, 2003. The EITF consensus on this issue is not considered final until ratified by the FASB, and the FASB is scheduled to consider ratification of the consensus reached by the EITF in August, 2003. Based upon knowledge of this matter to date, the Company does not anticipate that the adoption of EITF Issue No. 03-11 will have a material effect on its consolidated results of operations, cash flows or financial position.

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Subsequent Events

On July 9, 2003, the Company and Fluor Corporation announced that the D/FD partnership between subsidiaries of the two companies will be dissolved, at the request of Fluor Corporation. The partners of D/FD have adopted a plan for an orderly wind-down of the business of D/FD over the next two years. Many details of the dissolution of the partnership remain to be developed. The Company is still assessing the impact of this event but anticipates that the dissolution of this partnership will not have a material effect on its consolidated results of operations, cash flows or financial position.

In connection with the Company’s continued focus on non-strategic asset sales, on July 24, 2003, International Energy completed the sale of its 85.7% majority interest in PJP in Indonesia for $300 million, including $222 million in project debt, to Freeport-McMoRan Copper & Gold Inc. The $222 million of project debt included in the transaction represents the Company’s share of total project debt of $259 million, which remains with PJP. The sale will result in a reduction to the Company’s consolidated indebtedness of $259 million.

On August 12, 2003, the Company announced that it has entered into an agreement to sell 25% undivided interest in the Duke Energy Vermillion facility for approximately $44 million. The Company expects to record a loss on the sale of approximately $19 million during the third quarter of 2003. The Company will continue to own the remaining 75% interest in the facility. The sale is subject to regulatory approval but is expected to close by the second quarter of 2004.

For information on subsequent events related to regulatory matters, see Note 5 to the Consolidated Financial Statements, Notices of Proposed Rulemaking section. For information on subsequent events related to litigation and contingencies see Note 10 to the Consolidated Financial Statements, Litigation section. For information on subsequent events related to debt, credit facilities and other financing matters, see Note 8 to the Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market Price Risk

The Company, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its proprietary trading activities. The Company 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 for trading purposes. On April 11, 2003, the Company announced that it will be exiting proprietary trading at DENA and International Energy. The Company is also exposed to the impact of market fluctuations in commodity prices and interest rates as a result of its ownership of energy related assets and interest in structured contracts, as well as use of certain interest rate hedge instruments. The use of undesignated non-trading derivatives to manage these risks is reflected as other than trading. (See Notes 2 and 7 to the Consolidated Financial Statements.)

Hedging Strategies. Some Company subsidiaries are exposed to market fluctuations in the prices of energy commodities related to their power generating and natural gas gathering, processing and marketing activities. The Company 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 hedge the value of its assets and operations from such price risks. In accordance with SFAS No. 133, the Company’s primary use of energy commodity derivatives is to hedge the output and production of assets it physically owns. These contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by the Company.

Effective January 1, 2003, in connection with the implementation of the remaining provisions of EITF Issue No. 02-03, the Company designated as hedges certain contracts that were previously economic hedges

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under EITF Issue No. 98-10. Derivative contracts which were not designated as hedges continue to be reported under the mark-to-market accounting method.

The Company is also exposed to market fluctuations in interest rates and foreign exchange rates related to variable rate debt and ownership and investments in foreign operations. The Company closely monitors the risks associated with these exposures and, where appropriate, uses derivatives to hedge interest rate and foreign exchange rate exposures. These derivatives are designated and qualify as effective hedge positions of future cash flows, or fair values of the Company assets and liabilities.

As of June 30, 2003, the fair value of designated hedges on the Consolidated Balance Sheets of the Company was $1,133 million. This amount represents the combination of certain amounts presented as assets and liabilities for unrealized gains and losses on mark-to-market and hedging transactions on the Consolidated Balance Sheets.

Credit Risks. In addition to the risk associated with the market fluctuation in the price of natural gas, electricity and other energy-related products marketed and purchased, the Company is exposed to the risk of loss resulting from non-performance of contractual obligations by a counterparty. During 2003, certain counterparties who have contractual arrangements with the Company have either encountered financial difficulty or declared bankruptcy. The Company has taken active measures, such as the modification of collateral agreements and modification of existing contracts, to mitigate the risks associated with such counterparties and as of June 30, 2003, has not realized material losses from non-performance of such counterparties. While the Company has processes in place to monitor and attempt to mitigate economic exposures to these counterparties, the energy sector remains financially distressed.

Item 4. Controls and Procedures

The Company’s management, including the Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. The Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in the Company’s reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There have been no significant changes in the Company’s internal controls over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

In late 1999, the Company discovered that operations and maintenance personnel at its Moss Landing, California facility were occasionally “backflushing,” a practice initially implemented by the facility’s prior owner, to remove debris from the inlet side of the condensers. The flow of wastewater from this practice was not specifically authorized in the facility’s discharge permit. Upon its discovery, the Company promptly reported the noncompliance to the California Regional Water Quality Control Board (Control Board) and stopped the discharges. After ongoing discussions of this matter, the Company and the Control Board have agreed to the terms of a stipulated order with a civil penalty of $250,000, the bulk of which will be paid as a Supplemental Environmental Project. The Control Board formally approved the stipulated order on May 16, 2003.

For additional information concerning litigation and other contingencies, see Note 10 to the Consolidated Financial Statements, “Commitments and Contingencies;” and Item 3, “Legal Proceedings,” and Note 13 to the Consolidated Financial Statements, “Commitments and Contingencies,” in the Company’s Form 10-K/A for December 31, 2002, which are incorporated herein by reference.

Management believes that the final disposition of these proceedings will have no material adverse effect on the Company’s consolidated results of operations, cash flows or financial position.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

Exhibit Number
31.1	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the President Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

(b) Reports on Form 8-K

The Company filed no reports on Form 8-K during the second quarter of 2003.

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SIGNATURES

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

		DUKE CAPITAL CORPORATION
Date:	August 14, 2003	/s/    ROBERT P. BRACE
		Robert P. Brace Chairman of the Board and President
Date:	August 14, 2003	/s/    KEITH G. BUTLER
		Keith G. Butler Controller and Chief Financial Officer

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