Spectra Energy Capital 10-Q 2003 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended September 30, 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 October 31, 2003......1,010

DUKE CAPITAL CORPORATION

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

INDEX

Item		Page
PART I. FINANCIAL INFORMATION
1.	Financial Statements	1
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2003 and 2002	1
	Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002	2
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2003 and 2002	4
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2003 and 2002	5
	Notes to Consolidated Financial Statements	6
2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	36
3.	Quantitative and Qualitative Disclosures about Market Risk	59
4.	Controls and Procedures	60
PART II. OTHER INFORMATION
1.	Legal Proceedings	61
6.	Exhibits and Reports on Form 8-K	61
	Signatures	62

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, the situation in Iraq, 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

i

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

• 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

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

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.

ii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Operating Revenues
Sales of natural gas and petroleum products	$	2,476		$	1,145		$	8,359		$	3,567
Transportation and storage of natural gas		447			429			1,279			1,202
Electric generation		638			841			1,576			1,805
Other		191			84			722			532
Total operating revenues		3,752			2,499			11,936			7,106
Operating Expenses
Natural gas and petroleum products purchased		2,150			896			7,235			2,797
Fuel used in electric generation and purchased power		378			467			755			742
Other operation and maintenance		625			722			1,649			1,766
Depreciation and amortization		277			267			818			693
Property and other taxes		50			66			187			190
Impairment of goodwill		254			—			254			—
Total operating expenses		3,734			2,418			10,898			6,188
Loss on Sales of Other Assets, net		(105	)		(4	)		(78	)		(3	)
Operating (Loss) Income		(87	)		77			960			915
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		35			57			86			166
Gain on sale of equity investments		33			18			266			32
Other income and expenses, net		28			31			91			119
Total other income and expenses		96			106			443			317
Interest Expense		293			256			843			613
Minority Interest (Benefit) Expense		(10	)		3			80			76
(Loss) Earnings Before Income Taxes		(274	)		(76	)		480			543
Income Tax (Benefit) Expense		(168	)		(43	)		82			163
(Loss) Income Before Cumulative Effect of Change in Accounting Principles		(106	)		(33	)		398			380
Cumulative Effect of Change in Accounting Principles, net of tax		—			—			(52	)		—
Net (Loss) Income	$	(106	)	$	(33	)	$	346		$	380

See Notes to Consolidated Financial Statements.

1

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	September 30, 2003		December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	1,209	$	814
Receivables		2,566		4,579
Inventory		781		666
Unrealized gains on mark-to-market and hedging transactions		2,166		2,013
Other		637		717
Total current assets		7,359		8,789
Investments and Other Assets
Investments in unconsolidated affiliates		1,490		2,023
Goodwill, net of accumulated amortization		3,870		3,747
Notes receivable		358		589
Unrealized gains on mark-to-market and hedging transactions		2,774		2,173
Assets held for sale		257		—
Other		1,617		2,156
Total investments and other assets		10,366		10,688
Property, Plant and Equipment
Cost		30,671		29,238
Less accumulated depreciation and amortization		4,518		4,026
Net property, plant and equipment		26,153		25,212
Regulatory Assets and Deferred Debits		992		855
Total Assets	$	44,870	$	45,544

See Notes to Consolidated Financial Statements.

2

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)

	September 30, 2003		December 31, 2002
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	2,115	$	3,677
Notes payable and commercial paper		392		683
Taxes accrued		214		—
Interest accrued		234		236
Current maturities of long-term debt		975		1,148
Unrealized losses on mark-to-market and hedging transactions		1,712		1,744
Other		1,143		1,538
Total current liabilities		6,785		9,026
Long-term Debt		15,295		15,703
Deferred Credits and Other Liabilities
Deferred income taxes		3,516		3,222
Unrealized losses on mark-to-market and hedging transactions		2,160		1,439
Other		1,129		1,344
Total deferred credits and other liabilities		6,805		6,005
Commitments and Contingencies
Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation		—		825
Minority Interests		1,716		1,904
Common Stockholder’s Equity
Common stock, no par, 3,000 shares authorized, 1,010 shares outstanding		—		—
Paid-in capital		8,564		7,545
Retained Earnings		5,084		4,748
Accumulated other comprehensive income (loss)		621		(212	)
Total common stockholder’s equity		14,269		12,081
Total Liabilities and Stockholder’s Equity	$	44,870	$	45,544

See Notes to Consolidated Financial Statements.

3

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Nine Months Ended September 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	346		$	380
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		818			693
Cumulative effect of change in accounting principle		52			—
Gains on sales of equity investments and other assets		(188	)		—
Impairment charges		254			273
Deferred income taxes		134			7
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		5			396
Receivables		1,362			1,415
Inventory		(136	)		(18	)
Other current assets		(59	)		(150	)
Increase (decrease) in
Accounts payable		(1,222	)		(165	)
Taxes accrued		202			232
Other current liabilities		(267	)		(324	)
Other, assets		146			265
Other, liabilities		85			(332	)
Net cash provided by operating activities		1,532			2,672
CASH FLOWS FROM INVESTING ACTIVITIES
Capital and investment expenditures, net of refund		(1,266	)		(3,495	)
Acquisition of Westcoast Energy Inc., net of cash acquired		—			(1,707	)
Proceeds from the sale equity investments and other assets and sales of and collections on notes receivable		1,459			246
Other		(16	)		(110	)
Net cash provided by (used in) investing activities		177			(5,066	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		275			2,211
Payments for the redemption of long-term debt		(1,401	)		(748	)
Payments for the redemption of guaranteed preferred beneficial interests in subordinated notes		(250	)		—
Payments for the redemption of preferred member interests		(38	)		—
Notes payable and commercial paper		(838	)		92
Contributions from minority interests		1,958			1,931
Distributions to minority interests		(2,067	)		(1,692	)
Capital contributions from parent		1,050			650
Other		(3	)		55
Net cash (used in) provided by financing activities		(1,314	)		2,499
Net increase in cash and cash equivalents		395			105
Cash and cash equivalents at beginning of period		814			263
Cash and cash equivalents at end of period	$	1,209		$	368
Supplemental Disclosures
Non-cash Financing Activities
Reclassification of guaranteed preferred beneficial interests in subordinated notes to long-term debt	$	600			—
Reclassification of long-term debt to notes payable and commercial paper	$	500			—
Reclassification of preferred member interest to long-term debt		—		$	1,025

See Notes to Consolidated Financial Statements.

4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Net (Loss) Income	$	(106	)	$	(33	)	$	346		$	380
Other comprehensive income (loss):
Foreign currency translation adjustments		295			(230	)		698			(356	)
Net unrealized (losses) gains on cash flow hedges		(226	)		(391	)		464			(20	)
Reclassification of (gains) losses from cash flow hedges into earnings		(46	)		67			(248	)		(121	)
Other comprehensive income (loss) before income taxes		23			(554	)		914			(497	)
Income tax benefit (expense) related to items of other comprehensive income		104			115			(81	)		47
Total other comprehensive income (loss)		127			(439	)		833			(450	)
Total Comprehensive Income	$	21		$	(472	)	$	1,179		$	(70	)

See Notes to Consolidated Financial Statements.

5

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 as identified in Note 4.

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

	September 30, 2003		December 31, 2002
Materials and supplies	$	342	$	310
Gas		399		271
Petroleum products		40		85
Total inventory	$	781	$	666

Accounting for Risk Management and Trading Activities.The Company uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities, and its trading activities, including forward contracts, futures, swaps, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under 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 and energy-related 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.

6

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. Qualifying non-trading energy commodity and other 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), or a normal purchase or normal sale contract, while certain non-trading derivatives remain undesignated. Certain derivatives related to marketing and other risk management activities are designated as non-trading and reflected as other than trading in the table in Note 7. Derivatives designated as trading relate to the Company’s proprietary trading activities. The Company announced it is exiting proprietary trading at Duke Energy North America (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 Standards, 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 not held for trading purposes 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.

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 represent contracts related to the Company’s natural gas wholesale marketing operations that are not designated as normal purchase or sale contracts, 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 commodity derivatives are reported on a net basis in Other Operating Revenues.

• Gains and losses from undesignated non-trading currency derivatives are reported in Other Income and Expenses, net in the Consolidated Statements of Income.

• Gains and losses from undesignated non-trading interest rate derivatives are reported in Interest Expense in the Consolidated Statements of Income.

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 revenues and expenses 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.

7

The significant reduction, as of January 1, 2003, in the volume of derivative and non-derivative contracts that were considered to be trading resulted in presentation of gains and losses, or revenues and expenses for many contracts on a gross basis in 2003 that were presented on a net basis in 2002.

Where the Company’s derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation No. 39 (FIN 39), “Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and SFAS No. 105),” are met, the Company presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying balance sheets.

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

Goodwill(in millions)

	Balance December 31, 2002		Impairment Charge			Other a			Balance September 30, 2003
Natural Gas Transmission	$	2,760	$	—		$	370		$	3,130
Field Services		481		—			9			490
Duke Energy North America		100		(100	)		—			—
International Energy		246		—			(3	)		243
Other Operations		6		—			1			7
Other b		154		(154	)		—			—
Total consolidated	$	3,747	$	(254	)	$	377		$	3,870

^a Amounts consist primarily of foreign currency adjustments and purchase price adjustments to prior year acquisitions.

^b Amount represents goodwill that was allocated to DENA for the purpose of impairment testing pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets.” As a result, the impairment charge was recorded in the DENA segment.

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.”

Stock-Based Compensation.The Company accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Income. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are recorded over the vesting period as compensation cost and are adjusted for increases and decreases in market value up to the measurement date.

8

The following table shows what net income would have been if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards and reflect the provisions of SFAS No. 148, “Accounting for Stock-based Compensation – Transition and Disclosure (an amendment of FASB Statement No. 123).”

Pro Forma Stock-Based Compensation

(in millions)

	Three Months Ended, September 30,						Nine Months Ended, September 30,
	2003			2002			2003			2002
Net (Loss) Income, as reported	$	(106	)	$	(33	)	$	346		$	380
Add: stock-based compensation expense included in reported net income, net of related tax effects		—			3			5			8
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(6	)		(11	)		(20	)		(63	)
Pro forma net (loss) income, net of related tax effects	$	(112	)	$	(41	)	$	331		$	325

Comprehensive Income (Loss).Comprehensive income includes net income and all other nonowner changes in equity. The tax effect on other comprehensive income is as follows:

Comprehensive Income (Loss) (in millions)

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Nine Months Ended September 30, 2003
Foreign currency translation adjustments	$	698		$	—		$	698
Net unrealized gains (losses) on cash flow hedges		464			(174	)		290
Reclassification of (gains) losses from cash flow hedges into earnings		(248	)		93			(155	)
Other Comprehensive Income	$	914		$	(81	)	$	833
Nine Months Ended September 30, 2002
Foreign currency translation adjustments	$	(356	)	$	—		$	(356	)
Net unrealized gains (losses) on cash flow hedges		(20	)		(16	)		(36	)
Reclassification of (gains) losses from cash flow hedges into earnings		(121	)		63			(58	)
Other Comprehensive Loss	$	(497	)	$	47		$	(450	)

9

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 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 $81)		698			135		—			833
Balance as of September 30, 2003	$	45		$	590	$	(14	)	$	621

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, “Reporting Revenue Gross as a Principal versus Net as an Agent.

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.

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SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment of FASB Statement No. 123).” In December 2002, the FASB issued SFAS No. 148, which amends SFAS No. 123, and provides alternative methods of transition for a voluntary change to the fair value-based method of accounting for stock-based employee compensation. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123 and APB Opinion No. 28, “Interim Financial Reporting,” to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The disclosure provisions of SFAS No. 148 are included under “Stock-Based Compensation” above.

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 are to 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 continue to be applied based upon their original effective dates. The Company adopted the provisions of SFAS No. 149 on July 1, 2003. Certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity led the Company to re-evaluate its policy for accounting for forward sales contracts. As a result, the Company has elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges on a prospective basis. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 will continue to be accounted for under such exception, including following any modifications to these contracts, as long as the requirements for applying the normal purchases and normal sales exception are met.

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 does not anticipate that this Issue 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 has been applied to the Company’s existing financial instruments beginning on July 1, 2003.

As a result of the adoption of SFAS No. 150, Long-term Debt at September 30, 2003 includes $600 million of trust preferred securities which had been previously included on the Consolidated Balance Sheet as Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation. Long-term Debt at September 30, 2003 also includes approximately $23 million of one of the Company’s subsidiary’s preferred and preference stock which had been previously included on the Consolidated Balance Sheet as Minority Interests. In accordance with the requirements of SFAS No. 150, prior period amounts have not been reclassified to be in conformity with the current presentation. See Note 9 for further discussion of the impact of adoption of SFAS No. 150 on the Company’s trust preferred securities.

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The Company’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited life entities based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3. The Company continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on the Company’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant changes could be made by the FASB during such future deliberations. Therefore, the Company is not able to conclude as to whether such future changes would be likely to materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.

FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary 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 by the first fiscal year or interim period ending after December 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. The Company currently anticipates certain entities, previously accounted for under the equity method of accounting, will be consolidated by the Company as of December 31, 2003 under the provisions of FIN 46. These entities, which are substantive entities, have total assets of approximately $220 million as of September 30, 2003 and total revenue of approximately $110 million for the nine-months ended September 30, 2003. The Company’s maximum exposure to loss as a result of its involvement with these entities is approximately $100 million, generally limited to the Company’s investment and guarantee obligations in these entities as of September 30, 2003. Further, upon adoption of FIN 46, the Company anticipates deconsolidating the trusts that have issued the trust preferred securities, as discussed in Note 9, since the Company is not the primary beneficiary of such trusts. This deconsolidation will result in the Company reflecting an affiliate note payable to the trusts, rather than trust preferred securities, in the Consolidated Balance Sheets. Additionally, the Company has a significant variable interest in, but is not the primary beneficiary of, Duke COGEMA Stone & Webster, LLC (DCS) due to certain guarantee obligations as discussed in Note 11. As further discussed in Note 11, the Company’s maximum exposure to loss as a result of its variable interest in DCS cannot be quantified. 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. The FASB continues to interpret the provisions of FIN 46 and has issued an exposure draft to amend certain provisions of FIN 46 which is expected to become effective in the fourth quarter of 2003. Until such interpretations and amendments are finalized, the Company is not able to conclude as to whether such future changes would be likely to materially affect its consolidated results of operations, cash flows or financial position.

EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” In May 2003, the EITF reached consensus in EITF Issue No. 01-08 to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed

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to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, “Accounting for Leases.” The Company has historically provided and leased storage capacity to outside parties as well as entered into pipeline capacity agreements both as the lessee and as a lessor. Upon application of EITF Issue No. 01-08, the accounting requirements under the consensus could affect the timing of revenue and expense recognition, and revenues reported as transportation and storage services may be required to be reported as rental or lease income. Should capital-lease treatment be necessary, purchasers of transportation and storage services in the arrangements would be required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for as transportation and storage purchases or sales arrangements. The Company does not anticipate that the adoption of EITF Issue No. 01-08 will have a material effect 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 and the economic substance of the transaction. In analyzing the facts and circumstances, EITF Issue No. 99-19 and Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF Issue No. 03-11 is effective for transactions or arrangements entered into after September 30, 2003. 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. In addition, beginning in the third quarter of 2003, the Company elected to begin netting certain receivables and payables with common counterparties under the provisions of FIN 39. For comparability purposes, balances of certain receivables and payables in the comparative balance sheet presented in this quarterly report have been netted. Such netting reduced current assets and current liabilities as of December 31, 2002 by approximately $2 billion.

3. Business Acquisitions, Dispositions, Assets Held for Sale and Impairment

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 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

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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.

In September 2003, the Company recorded an additional purchase price adjustment related to the Westcoast acquisition as additional information about taxes became available. As a result, the deferred tax asset based on the initial purchase price allocation was changed to reflect the revised tax basis of certain assets acquired, with an offsetting increase to goodwill attributable to the acquisition. The purchase price amounts in the following table reflect these additional adjustments.

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

Operating revenues would have been $7,424 million and net income would have been $417 million for the nine months ended September 30, 2002 if the Westcoast acquisition had taken place at January 1, 2002.

Dispositions.In first quarter 2003, the Company sold partnership interests in Northern Borders L.P. for approximately $24 million. The Company recorded a pre-tax gain of approximately $14 million, which is included in Gain on Sale of Equity Investments in the Consolidated Statements of Income.

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, which is included in Gain on Sale of Equity Investments in the Consolidated Statements of Income. In October 2003, the remaining 2.1% of the 23.6% ownership interest in the U.S. segment of Alliance Pipeline was sold to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $11 million. The Company obtained its minority ownership 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. This sale resulted in a pre-tax gain of approximately $11 million, which is included in Gain on Sale of Equity Investments in the Consolidated Statements of Income. 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, Duke Energy Field Services (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 approximate 70% share),

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which is included in (Loss) Gain on Sales of Other Assets, net in the Consolidated Statements of Income. 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 $325 million to Highstar Renewable Fuels LLC. The Company recorded a gain on the sale of approximately $178 million, which is included in Gain on Sale of Equity Investments in the Consolidated Statements of Income.

In July 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $78 million to Freeport-McMoRan Copper & Gold Inc. The sale resulted in a reduction to the Company’s consolidated indebtedness of $259 million. The Company recorded a loss on the sale of approximately $2 million, which is included in (Loss) Gain on Sales of Other Assets, net in the Consolidated Statements of Income.

In August 2003, Natural Gas Transmission completed the sale of its 50% interest in Foothills Pipe Lines Ltd. to TransCanada Pipelines Limited for $75 million. The Company recorded a gain on the sale of approximately $30 million, which is included in Gain on Sale of Equity Investments in the Consolidated Statements of Income.

On April 2003, DENA announced that it will discontinue proprietary trading. In addition, DENA and its partner are currently executing a reduction of Duke Energy Trading and Marketing LLC’s (DETM) business in scope and scale. In July 2003, DENA and its partner began to solicit interest from selected parties for a significant portion of DETM’s contract portfolio. The ultimate financial impact to DENA of the reduction in the scope and sale of DETM and related liquidation of its contract portfolio cannot be reasonably estimated. However, it is possible that DENA will incur losses as a result of liquidating the DETM contracts.

Application of SFAS No. 144. The Company evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable under the guidance of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”For long-lived assets, the Company determines the carrying amount is not recoverable if such amount exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the sum of the estimates of the undiscounted cash flows is less than the carrying value of the asset, the asset’s carrying value is adjusted to the lower of the carrying value or its estimated fair value. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of the asset, would generally require management to re-assess the cash flows related to the long-lived assets.

Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power and costs of fuel over periods of time consistent with the useful lives of the assets. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, The Company uses a probability-weighted approach for developing estimates of future cash flows to test the recoverability of its long-lived assets. A change in the Company’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. If the carrying value of the long-lived assets is not recoverable based on these estimated future cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of the long-lived assets using commonly accepted techniques including, but not limited to, recent third party comparable sales and discounted cash flow analysis.

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Judgment is involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144. The Company uses the following criteria, along with the other criteria contained in SFAS No. 144, to determine when an asset is classified as held for sale and therefore measured at the lower of its carrying amount or fair value less cost to sell:

• Management, having the authority to approve the action, commits to a plan to sell the asset. Depending upon the dollar threshold of the disposal, a disposal may require the Company’s Board of Directors approval based on the Company’s current governance structure;

• The asset is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets; and

• An active program to locate a buyer and other actions required to complete the plan to sell the assets have been initiated;

• The sale of the asset is probable, and transfer is expected to qualify for recognition as a completed sale within one year, except as permitted by paragraph 31 of SFAS No. 144;

• The asset is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and

• Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

In August 2003, DENA announced that it entered into an agreement to sell a 25% undivided interest in the wholly-owned Duke Energy Vermillion facility to Wabash Valley Power Association, Inc. In connection with the anticipated sale, the Company classified such assets as held for sale and recorded a loss in accordance with SFAS No. 144 of $18 million, which represents the excess carrying value of the 25% undivided interest in Duke Energy Vermillion over the fair market value less costs to sell those assets. The loss is included in (Loss) Gain on Sales of Other Assets, net on the Consolidated Statements of Income. As of September 30, 2003 the net carrying value of the 25% interest, which has been classified as Assets Held for Sale on the Consolidated Balance Sheets, was approximately $44 million. DENA will continue to own the remaining 75% interest in the facility, and there was no impairment on this portion. The sale is subject to regulatory approval but is expected to close by the second quarter of 2004.

In the third quarter 2003, DENA performed an impairment analysis on all merchant generation assets in accordance with SFAS No. 144 as a result of the continued decline in the merchant generation sector. Certain turbines and related equipment were reclassified as held for sale in accordance with SFAS No. 144. A loss of $66 million was recorded which represents the excess of carrying value over the estimated fair market value of the turbines and related equipment, less estimated cost to sell, and is included in (Loss) Gain on Sales of Other Assets, net in the Consolidated Statements of Income. As of September 30, 2003 the net carrying value of the turbines and major equipment was $124 million and is classified as Assets Held for Sale on the Consolidated Balance Sheets. These assets are expected to be sold over the next twelve months.

In September 2003, the notes receivable portfolio for Duke Capital Partners, LLC (DCP) was reclassified as assets held for sale. A loss of $23 million, which represents the excess of carrying value over the fair market value, less costs to sell, of the notes receivable is included in (Loss) Gain on Sales of Other Assets, net in the Consolidated Statements of Income. As of September 30, 2003 the net carrying value of the notes receivable was approximately $89 million and is classified as Assets Held for Sale on the Consolidated Balance Sheets.

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The Company expects the remaining portfolio will either mature or be sold before the end of June 2004.

The Company continues to consider opportunities to dispose of certain of its assets including negotiations at various stages with prospective buyers (see also Note 13). In the event that additional dispositions occur, losses would be recorded if sales proceeds were less than carrying values. Based on certain market conditions in the merchant energy sector, if the Company were to dispose of certain merchant energy assets in the near term or if the probability of sale was high enough to result in an impairment under the requirements of SFAS No. 144, the Company would likely incur significant losses. Under the provisions of SFAS No. 144, these losses could be incurred prior to the period of the actual closing of sales.

Impairment of Goodwill.The Company evaluates the impairment of goodwill under SFAS No. 142. As required by SFAS No. 142, the Company performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. As a result of the annual impairment test, the Company recorded a $254 million goodwill impairment charge in the third quarter 2003 to write off all DENA goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflects the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. The Company used a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, the Company incorporated current market information as well as historical factor and fundamental analysis as well as other factors into its forecasted commodity prices.

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 expense related to those profits.

In 2003, the business segments formerly known as Other Energy Services and Duke Ventures were combined and are now presented as Other Operations. Other Operations is composed of diverse businesses operating through Crescent Resources LLC, DukeNet Communications LLC), DCP, Duke/Fluor Daniel (D/FD) and Energy Delivery Services, Inc. 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 D/FD partners have adopted a plan for an orderly wind-down of the business over the next two years. Many details of the dissolution are in the process of being developed. The Company is still assessing the impact of this event, but anticipates that it will have no material effect on its consolidated results of operations, cash flows or financial position.

Consolidated EBIT is viewed as a non-GAAP measure under the rules of the Securities and Exchange Commission (SEC). However, the Company includes 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 interest in operations without regard to financing methods or capital structures.

On a consolidated basis, EBIT is also used as a performance measure and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Income. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and the Company believes its investors use EBIT as a supplemental measure to evaluate 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 and EBIT to Net Income(in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Operating (loss) income	$	(87	)	$	77		$	960		$	915
Other income and expensesa		96			106			443			317
EBIT		9			183			1,403			1,232
Interest expense		293			256			843			613
Minority interest (benefit) expense		(10	)		3			80			76
(Loss) earnings before income taxes		(274	)		(76	)		480			543
Income tax (benefit) expense		(168	)		(43	)		82			163
(Loss) income before cumulative effect of change in accounting principles		(106	)		(33	)		398			380
Cumulative effect of change in accounting principles, net of tax and minority interest		—			—			(52	)		—
Net (loss) income	$	(106	)	$	(33	)	$	346		$	380

^a Includes gains on sales of equity investments

EBIT should not be considered an alternative to, or more meaningful than, net income or operating 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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In the following table, EBIT includes the profit on intersegment sales at prices management believes are representative of arms-length transactions. The “Other” line item primarily includes certain unallocated corporate costs, and the elimination of intercompany profits from D/FD’s earnings for energy plants under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

Business Segment Data(in millions)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures
Three Months Ended September 30, 2003
Natural Gas Transmission	$	590		$	51		$	641		$	280		$	98	$	172
Field Services		1,761			80			1,841			53			75		32
Duke Energy North America		931			33			964			(416	)		68		11
International Energy		295			—			295			44			25		18
Total reportable segments		3,577			164			3,741			(39	)		266		233
Other Operations		166			—			166			38			7		78
Other		7			20			27			(7	)		4		22
Eliminations, reclassifications and minority interests		2			(184	)		(182	)		5			—		—
Third-party interest income		—			—			—			5			—		—
Foreign currency remeasurement gain		—			—			—			7			—		—
Total consolidated	$	3,752		$	—		$	3,752		$	9		$	277	$	333
Three Months Ended September 30, 2002
Natural Gas Transmission	$	574		$	54		$	628		$	288		$	96	$	235
Field Services		1,113			205			1,318			23			74		66
Duke Energy North America		782			(298	)		484			(123	)		61		237
International Energy		204			(1	)		203			(41	)		27		133
Total reportable segments		2,673			(40	)		2,633			147			258		671
Other Operations		70			51			121			57			7		100
Other		—			(93	)		(93	)		(32	)		2		12
Eliminations, reclassifications and minority interests		(244	)		82			(162	)		(7	)		—		—
Third-party interest income		—			—			—			21			—		—
Foreign currency remeasurement gain		—			—			—			(3	)		—		—
Total consolidated	$	2,499		$	—		$	2,499		$	183		$	267	$	783

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Business Segment Data(in millions)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures
Nine Months Ended September 30, 2003
Natural Gas Transmission	$	2,105		$	196		$	2,301		$	1,009		$	292	$	603
Field Services		5,544			674			6,218			162			229		94
Duke Energy North America		2,801			168			2,969			(191	)		187		268
International Energy		1,043			—			1,043			209			77		61
Total reportable segments		11,493			1,038			12,531			1,189			785		1,026
Other Operations		423			2			425			85			22		215
Other		18			58			76			12			11		25
Eliminations, reclassifications and minority interests		2			(1,098	)		(1,096	)		97			—		—
Third-party interest income		—			—			—			10			—		—
Foreign currency remeasurement gain		—			—			—			10			—		—
Total consolidated	$	11,936		$	—		$	11,936		$	1,403		$	818	$	1,266
Nine Months Ended September 30, 2002
Natural Gas Transmission	$	1,575		$	124		$	1,699		$	867		$	240	$	2,525
Field Services		3,120			708			3,828			99			219		250
Duke Energy North America		1,824			(755	)		1,069			47			129		1,758
International Energy		709			2			711			73			79		350
Total reportable segments		7,228			79			7,307			1,086			667		4,883
Other Operations		378			54			432			163			19		384
Other		—			—			—			(149	)		7		12
Eliminations, reclassifications and minority interests		(500	)		(133	)		(633	)		49			—		—
Third-party interest income		—			—			—			69			—		—
Foreign currency remeasurement gain		—			—			—			14			—		—
Cash acquired in acquisitions		—			—			—			—			—		(77	)
Total consolidated	$	7,106		$	—		$	7,106		$	1,232		$	693	$	5,202

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)

	September 30, 2003		December 31, 2002
Natural Gas Transmission	$	16,080	$	15,168
Field Services		6,520		6,941
Duke Energy North America		14,140		14,302
International Energy		4,674		5,804
Total reportable segments		41,414		42,215
Other Operations		2,047		2,316
Other, net of eliminations		1,409		1,013
Total consolidated assets	$	44,870	$	45,544

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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 September 30, 2003, the amount of accumulated depreciation on the Consolidated Balance Sheet related to this regulatory liability was 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 Federal Energy Regulatory Commission (FERC) issued two proposals that would require that market participants who operate under market-based rates for electric sales and 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. The Company filed comments on the FERC’s proposed conditions on August 18, 2003.

Final Rule on Cash Management Practices. In October 2003, the FERC issued a Final Rule implementing documentation and reporting requirements for FERC-regulated entities that participate in cash management programs. FERC-regulated entities must maintain written records of cash management programs and file these agreements with the FERC. Additionally, FERC-regulated entities must 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 changes are effective 30 days after publication in the Federal Register. The Company is preparing the necessary documentation to comply with the new requirements. Management expects the Final Rule to have no material adverse effect on the consolidated results of operations, cash flows or financial position.

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-fired power plants, obligations related to right-of-way agreements and contractual leases for land use.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

In accordance with SFAS No. 143, 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.

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Certain of the Company’s regulated operations recognize some removal costs as a component of depreciation for property that does not have an associated legal retirement obligation, in accordance with regulatory treatment. As discussed in Note 5, these amounts will remain in accumulated depreciation.

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 a 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 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 nine-month period ended September 30, 2003.

Reconciliation of Asset Retirement Obligation Liability for the Nine-Month Period Ended September 30, 2003(in millions)

Balance as of January 1, 2003	$	69
Accretion expense and other		6
Balance as of September 30, 2003	$	75

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 prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. On April 11, 2003, the Company announced that it will be exiting proprietary trading at DENA and International Energy. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.

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

Derivative Portfolio Carrying Value(in millions)

	September 30, 2003			December 31, 2002
Trading	$	195		$	312
Other than Trading		(11	)		—
Hedging		884			691
Total	$	1,068		$	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 Company’s Consolidated Balance Sheets. All amounts in the table represent fair value except that the net asset amounts shown for hedging include assets of $510 million and $720 million as of September 30, 2003 and December 31, 2002, respectively, that were frozen at the Company’s initial application of the normal purchases and normal sales exception to its forward power sales contracts as of July 1, 2001. These balances will reduce upon settlement of the associated contracts.

Commodity Cash Flow Hedges. As of September 30, 2003, $232 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 counterparties. To reduce credit risk exposure and mitigate counterparty credit risk, where available, the Company enters into netting agreements with counterparties that permit offset of receivables and payables with such counterparties. 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. The company has recognized losses through increased credit reserves. While the Company has the 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. The short-term loan was used for working capital and other general corporate purposes. The short-term loan matured in September 2003, but was able to be repaid at any time prior to its maturity date. The short-term loan had 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. During the third quarter of 2003, DEFS repaid the entire short-term loan with funds generated from assets sales and operations.

In September 2003, PanEnergy Corp, a wholly owned subsidiary of the Company, called $328 million of 7.75% bonds due in 2022. The bonds were redeemed at 102% of their aggregate principal amount. The pre-tax loss of approximately $13 million on the early extinguishment of the debt was recorded as Interest Expense in the Consolidated Statements of Income.

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Additionally, 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. As of September 30, 2003, there was no commercial paper included in Long-term Debt.

For information on the impact of the adoption of SFAS No. 150 on Long-term Debt see Notes 2 and 9.

During the nine-month period ended September 30, 2003, the Company reduced its credit facilities available by approximately $1.9 billion. 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 September 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: (1) nonpayment or (2) acceleration of other significant indebtedness of the applicable borrower or certain of its subsidiaries.

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 SFAS No. 150, effective July 1, 2003, as discussed in Note 2, the Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation have been reclassified on the September 30, 2003 Consolidated Balance Sheet: $600 million of trust preferred securities has been reclassified to Long-term Debt and $17 million of unamortized debt issue costs has been reclassified as Other Deferred Debt Expense. The $600 million of trust preferred securities are mandatorily redeemable financial instruments under the provisions of SFAS No. 150, since they are redeemable in cash, at par value, on or prior to a specified maturity date, ranging from 2029 to 2039. In addition, the Company has the option to redeem these financial instruments before their maturity date any time after five years from the date of issuance, or upon the occurrence of certain contingent events. Also, effective July 1, 2003, in accordance with the provisions of SFAS No. 150, the amortization of related debt issue costs and interest payments associated with the trust preferred securities have been classified on the Consolidated Statements of Income as Interest Expense rather than Minority Interest Expense. In accordance with the requirements of SFAS No. 150, prior period amounts have not been reclassified.

10. Commitments and Contingencies

Litigation.California Litigation.Duke Energy, some of its subsidiaries and three current or former executives have been named as defendants, along with numerous other corporate and individual defendants, in one or more of a total of 15 lawsuits filed in California on behalf of purchasers of electricity in the State of California, with one suit filed on behalf of a Washington state electricity purchaser. Most of these lawsuits seek class-action certification and damages and other relief as a result of the defendants’ alleged unlawful manipulation of the California wholesale electricity markets. These lawsuits generally allege that the defendants manipulated the wholesale electricity markets in violation of state laws against unfair and unlawful business practices and, in some suits, in violation of state antitrust laws. Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained revenues for sales of electricity and, in some lawsuits, an award of treble damages for alleged violations of state antitrust laws.

The first six of these lawsuits were filed in late 2000 through mid-2001 and were consolidated before a single judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master Amended Complaint in March 2002, which added additional defendants. The claims against the additional defendants are similar to those in the original complaints. In April 2002, some defendants, including Duke Energy, filed cross-complaints against various market participants not named as defendants in the plaintiff’s original and amended complaints. In May 2002, certain cross-defendants removed these actions to federal court in San Diego.

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The other nine of these 15 suits were filed in mid-to late 2002. The state court suits have been removed to federal court, and all suits have been transferred to federal court in San Diego for pre-trial consolidation with the previously filed six lawsuits. In December 2002, the court ordered the remand of the original six suits, and certain defendants and cross-defendants have appealed that ruling. In February 2003, the Court of Appeals for the Ninth Circuit issued an order accepting the appeal and stayed the remand order of the district court.

In January 2003, the federal court in San Diego granted the motion of the defendants to dismiss the suit filed by the Washington state plaintiff. The court ruled that the plaintiff’s state law claims, including alleged violations of the California antitrust and unfair business practices laws, were barred on filed rate and federal preemption grounds. The plaintiffs are appealing this ruling. In August 2003, the same judge granted the defendants’ motions to dismiss seven additional class action lawsuits, also on filed rate and federal preemption grounds. Plaintiffs in these cases also have appealed these dismissals.

Natural Gas Litigation. 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.

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 but granted leave to the plaintiffs to amend the complaint with certain restrictions so as not to contravene the intent of the ruling. The plaintiffs filed an amended complaint in August 2003.

Related Disputes.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 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

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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.

Subsidiaries of DENA, pursuant to transactions conducted through DETM, supplied electric power to two California electric utilities, Southern California Edison Company (SCE) and Pacific Gas & Electric Company (PG&E), under direct contracts and indirectly through the California Independent System Operator (CAISO) and the California Power Exchange (CalPX). During the period of energy shortages in California in 2000 and 2001, both utilities publicly acknowledged having serious cash flow issues and announced that they expected to run short of cash to pay all of their suppliers and other creditors. In January 2001, DETM notified SCE that it was in default on certain obligations, and DETM thus was terminating its bilateral contracts with SCE. Since then, the parties have unsuccessfully attempted to resolve disagreements relating to monies that each party claims is due as a result of the termination of the contracts. In late August 2003, SCE provided notice to DETM that it intends to invoke dispute resolution procedures over those disagreements. DETM has sought in excess of $18 million as a termination payment under the pertinent contracts. SCE disputes DETM’s calculations and contends that DETM owes in excess of $80 million to SCE in connection with the terminations. In July 2003, PG&E served a petition on DETM demanding arbitration of a dispute concerning the calculation of amounts allegedly owed by DETM to PG&E in connection with DETM’s termination of a power purchase agreement with PG&E in February 2001. PG&E alleges that it is owed in excess of $25 million relating to adjustments in offsets taken against amounts owed pursuant to the contract termination. DETM disputes this liability.

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 CAISO and the 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 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

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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.

The FERC issued three orders on October 16, 2003, in response to various motions for rehearing and for clarification relating to the refund proceeding and on-going investigations and enforcement proceedings. The FERC affirmed most features of its prior refund-related orders but did announce some clarifications and corrections. The orders require the CalPX and CAISO to take steps necessary to calculate the refund amounts (before taking into account any fuel cost credits) by mid-March 2004.

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. DETM responded to this Order on September 2, 2003. The FERC Order encouraged parties to consider settlement of these issues through discussions with the FERC trial staff. DETM is having such discussions, but will continue to vigorously defend its conduct in the Western markets. An Administrative Law Judge has set a schedule for a hearing in this case, with an Initial Decision expected by July 2, 2004. 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.

At the state level, the California Public Utilities Commission is conducting formal and informal investigations to determine if power plant operators in California, including some Duke Energy entities, have improperly “withheld,” either economically or physically, generation output from the market to manipulate market prices. In addition, the California State Senate formed a Select Committee to Investigate Price Manipulation of the Wholesale Energy Market (Select Committee). The Select Committee served a subpoena on Duke Energy and some of its subsidiaries seeking data concerning their California market activities. The Select Committee heard testimony from several witnesses but no one from Duke Energy has been subpoenaed to testify.

The California Attorney General is also conducting an investigation to determine if any market participants engaged in illegal activity, including antitrust violations, in the course of their electricity sales into wholesale markets in the western U.S. The Attorneys General of Washington and Oregon are participating in the California Attorney General’s investigation. The San Diego District Attorney is conducting a separate investigation into market activities and issued subpoenas to DETM and a DENA subsidiary.

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The U.S. Attorney’s Office in San Francisco served a grand jury subpoena on Duke Energy in November 2002 seeking, in general, information relating to possible manipulation of the electricity markets in California, including potential antitrust violations. As with the other ongoing investigations related to the California electricity markets, Duke Energy is cooperating with the U.S. Attorney’s Office in connection with its investigation.

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 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. Management expects the terms of the settlements to have no material adverse effect on the consolidated results of operations, cash flows or financial position.

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 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. 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. On September 17, 2003, the New York court issued a written opinion indicating that the court’s prior ruling constitutes a dismissal with prejudice, such that the plaintiffs are not allowed to re-plead their case. Plaintiffs have appealed this dismissal order to the Second Circuit United States Court of Appeals. 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 initially appealed the dismissal, but later dismissed the appeal. All but two of the original 17 shareholder suits now have been dismissed. Plaintiffs have agreed to dismiss the remaining two cases and a stipulation seeking this dismissal has been filed with the North Carolina federal court. 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. No request for a response has been received to date.

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In July 2003, a former trader with DEM 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. The defendants have filed a motion to dismiss the plaintiff’s claims.

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 asked 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 also responded 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.

In September 2003, DETM and the CFTC reached a settlement regarding reporting prior to September 2002, of natural gas trading information to publications that compile and report index prices. On September 17, 2003, the CFTC filed and simultaneously approved an order settling an administrative action against DETM. The CFTC order states DETM’s Houston offices knowingly reported trades that did not occur and reported certain trades at false prices and/or volumes. DETM agreed to pay a civil penalty of $28 million without admitting or denying the commission’s findings. The Company recorded a $17 million charge, net of minority interest, in the third quarter of 2003 to reflect the settlement. The previous practices in question were isolated in one area of DETM, its natural gas trading operation in the Eastern market, based in Houston.

DETM made changes to its reporting process in 2002, as soon as industry-wide natural gas reporting problems were identified. DETM now requires that all data provided to indices be validated and conveyed by risk management staff reporting to Duke Energy’s chief risk officer, rather than by trading personnel. DETM’s internal reviews of its Western trading operations confirmed appropriate price reporting practices for both electricity and natural gas. In Houston, DETM found no problems with electricity price reporting. DETM has terminated or otherwise disciplined certain Houston-based natural gas traders. DETM is not aware of any evidence that the previous practices in question affected any published index price.

In August and October, 2003 two class action lawsuits brought on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002 were filed in the U.S. District Court for the Southern District of New York against numerous defendants, including Duke Energy, seeking damages for alleged violations of the Commodities Exchange Act and for allegedly aiding and abetting such violations. Plaintiffs claim that, during the referenced time period, the defendants reported false and misleading trading information, including inflated volume and price information to trade publications, resulting in monetary losses to the plaintiffs. In addition, they allege that certain defendants, not including Duke Energy, engaged in “wash trades” for the purpose of artificially inflating the price of natural gas. Plaintiffs seek class action certification, actual damages in unspecified amounts, costs, attorneys’ fees and other appropriate relief.

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

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(the LNG Agreements) relating to Duke LNG’s 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 LNG Agreements as a result of, among other things, Duke LNG’s 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. The arbitration was bifurcated into liability and damages phases, with the liability phase concluding in March 2003. On July 11, 2003, the arbitration panel 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 arbitration panel 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 LNG 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 Duke LNG’s 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 denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach entitling Citrus to terminate the agreement and recover resulting damages. 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 appeal was held at the district court level on September 19, 2003. On July 11, 2003, Enron filed its proposed plan of reorganization for the bankruptcy, and filed an amended plan on September 18, 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.

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AES Puerto Rico LP (AES).On June 9, 2003, AES filed suit against Duke/Fluor Daniel Caribbean, S.E. (D/FD Caribbean) and others, including Duke Capital Corporation, in Delaware federal court, alleging claims in excess of $100 million arising out of the construction by D/FD Caribbean of a coal fired power plant in Puerto Rico. D/FD Caribbean disputes the allegations made by AES and has alleged its own claims, which are in excess of $50 million. Duke Energy holds an indirect 50% ownership interest in both D/FD Caribbean and its affiliate D/FD. D/FD Caribbean is involved in settlement negotiations with AES.

Hubline Construction Disputes.A number of disputes have arisen between Algonquin Gas Transmission Company (Algonquin) and several of its contractors and their subcontractors who provided construction and related services for Algonquin’s “Hubline” gas pipeline in Boston Harbor, Massachusetts. These disputes center on claims of underpayment by contractors and certain subcontractors and claims of overpayment by Algonquin, as well as claims relating to performance and other construction-related disputes. To date, two groups of lawsuits have been filed, one in Louisiana and the other in Massachusetts, by certain subcontractors against the primary contractor, Stolt Offshore, Inc. (Stolt) and Algonquin. Duke Energy is also named in the Louisiana subcontractor suit. These subcontractor suits allege that Stolt did not pay the plaintiff subcontractors for all of the work they invoiced Stolt for the Hubline project. An arbitration was commenced in late October 2003 relating to the construction disputes between Stolt and Algonquin, some of which relate to Stolt’s alleged underpayment of certain of its subcontractors. Some of the claims between Algonquin, Stolt and other third party contractors and subcontractors have progressed through early phases of dispute resolution and are the subject, in part, of the recent arbitration filing. In addition, certain of the construction and payment disputes stem from the related Phase III expansion of Duke Energy’s Maritimes & Northeast Pipeline and those claims are also in the early phases of dispute resolution. The amount of the parties’ various claims is not quantifiable at this time.

Other Litigation and Legal Proceedings.The Company and 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.

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, which has been included as an investing activity in the Consolidated Statements of Cash Flows. The transaction has been accounted for as 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. 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 at a DOE host site (MOX FFF). The domestic MOX fuel project was prompted by

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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 September 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 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 related facilities so that MOX fuel can be irradiated, 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. On September 30, 2003, the DOE and the DCS amended the Prime Contract (i) to provide that the first option phase be divided into a first segment of the first option phase, covering the modification of the Nuclear Reactors and related facilities so that MOX fuel can be irradiated, and a second segment of the first option phase, covering the construction and cold startup of the MOX FFF; and (ii) to reflect the DOE’s exercise of its right to extend the term of the Prime Contract to cover the first segment of the first option and add the related terms and conditions. As of September 30, 2003, DCS’ performance obligations under the Prime Contract include only the Base Contract phase and the first segment of the first option phase, since the DOE has not yet exercised its option to extend the term of performance under the Prime Contract to the second segment of the first option phase, and DCS and the DOE have not yet agreed on all open terms and conditions applicable to the second segment.

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 DCS MOX 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. On October 29, 2003, Duke Power and DCS amended the Duke Power Subcontract (i) to provide for the performance of an initial segment of the first option phase (Implementation of Mission Reactors and Site Modifications) on a cost reimbursement plus incentive fee

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basis and (ii) to recognize DCS’ right to extend the term of the Duke Power Subcontract to cover remaining segments of the first option phase under the terms and conditions set forth in the Duke Power Subcontract. As of October 29, 2003, Duke Power’s performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the initial segment of the first option phase, since DCS has not yet exercised its option to extend the term of performance under the Duke Power Subcontract to any further segment of the first option phase, and DCS and Duke Power have not yet agreed on open terms and conditions applicable to such segment(s) of 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 September 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 September 30, 2003 was approximately $2.7 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 the payment and performance of less than wholly owned consolidated entities. Approximately $10 million of the performance guarantees expire in 2003 approximately $50 million expire in 2004, and approximately $600 million expire in 2005 and thereafter, 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.

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 September 30, 2003 was approximately $50 million. Of these guarantees, approximately $30 million expire from 2004 to 2007, with the remainder expiring after 2007 or having no contractual expiration.

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The Company uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, the Company has payment obligations to the issuing bank which are triggered by a draw by the third party or customer under the letter of credit due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. 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 September 30, 2003 was approximately $450 million. Of this amount, approximately $300 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities, and approximately $100 million relates to affiliated entities such as Duke Energy Fuels and DEM.

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 September 30, 2003, the Company had guaranteed approximately $80 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, Natural Gas Transmission and International Energy have issued certain guarantees of debt associated with non-consolidated entities and less than wholly-owned entities. In the event that non-consolidated entities or less than wholly-owned entities default on the debt payments, Field Services, Natural Gas Transmission or International Energy would be required to perform under the guarantees and make payment on the outstanding debt balance of the non-consolidated entity. As of September 30, 2003, Field Services was the guarantor of approximately $90 million of debt associated with non-consolidated entities. Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly-owned entities. International Energy was the guarantor of approximately $15 million of debt associated with non-consolidated entities. These guarantees principally expire in 2003 for Field Services, 2019 for Natural Gas Transmission, and 2004 for International Energy.

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 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.

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As of September 30, 2003, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial both individually and in the aggregate.

12. Subsequent Events

On October 1, 2003, the Company completed the sale of its 30% interest in Vector Pipeline to Enbridge Inc. and DTE Energy Company for $145 million. The Company expects to record the sale during the fourth quarter of 2003. Each company paid $72.5 million for an equal share of the Company’s previous 30% ownership stake. The Vector Pipeline transports Western Canadian natural gas from the Chicago area market hub to the hub at Dawn, Ontario. The Company acquired ownership interest in the pipeline through its 2002 acquisition of Westcoast.

Subsequent to October 31, 2003, management committed to a plan to sell one of DENA’s merchant power generation facilities. The carrying value of the facility as of September 30, 2003 was approximately $220 million, and the anticipated net sales proceeds are approximately $140 million, resulting in a pre-tax loss of approximately $80 million that the Company expects to record in the fourth quarter of 2003. The amount of the loss is subject to the resolution of the completion of certain terms and conditions that may impact the final amount. The sale of the facility is expected to be completed within the next twelve months.

As of October 31, 2003, management committed to a plan to sell its Dutch-based gas marketing business. The carrying value of this business was approximately $60 million as of September 30, 2003 and the anticipated net sales proceeds are approximately $80 million. The amount of the anticipated gain will depend on the final terms and conditions of the proposed sale and will be recorded at the time of closing, which is expected to occur in the fourth quarter of 2003, subject to approval by the European Commission. In connection with the sale and during the balance of 2003 and 2004, the Company expects to incur expenses of approximately $40 million related to the winding-down of its remaining European gas marketing operations.

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 11, 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 these and other services through its business segments as identified in Note 4 to the Consolidated Financial Statements.

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

RESULTS OF OPERATIONS

Overview

For the three months ending September 30, 2003, net loss was $106 million. For the comparable 2002 quarter, net loss was $33 million. Key drivers of the 2003 lower results included:

• Severance charges of $59 million across all segments except Field Services

• An impairment of all goodwill at Duke Energy North America (DENA), related primarily to the trading and marketing business, of $254 million (see Note 3 to the Consolidated Financial Statements)

• Net losses of $72 million on equity investments, and other assets sold or held for sale (see Note 3 to the Consolidated Financial Statements)

• A settlement with the Commodity Futures Trading Commission (CFTC) of $17 million, net of minority interest expense, by DENA (see Note 10 to the Consolidated Financial Statements)

• Lower spark spreads (the difference between the value of electricity and the value of the gas required to generate the electricity) at DENA

• Foregone earnings of assets sold earlier in the year

• Fewer plant completions at Duke/Fluor Daniel (D/FD)

• Decreased capitalized interest of approximately $33 million, resulting primarily from DENA’s significantly lower plant construction activity in 2003

The above drivers were partially offset by a $52 million income tax benefit related to the write-off of goodwill at International Energy’s European operations in 2002, improved natural gas liquid pricing, and improved Latin American and European operations. Also, the Company recorded $298 million of charges in the third quarter of 2002 related to severance, the termination of certain turbines on order, impairments of other uninstalled turbines, write-off of site development costs, demobilization costs related to deferred plants and a partial impairment of a merchant plant.

For the nine months ending September 30, 2003, net income was $346 million. For the comparable 2002 period, net income was $380 million. In addition to the items described above, the following were key drivers for the change in the nine month period:

• Increased interest expense of $230 million due primarily to decreased capitalized interest and higher average debt balances, primarily resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast Energy, Inc. (Westcoast)

• 2003 charges related to changes in accounting principles of $52 million, net of tax and minority interest (see Note 2 to the Consolidated Financial Statements)

The above decreases in earnings for the nine months were partially offset by additional earnings from the Westcoast acquisition, and net gains on equity investments and other asset sales in the first six months of the year.

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For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the change in accounting principles, see “Other Impacts on Net Income” at the end of this section.

Consolidated Operating Revenues

Consolidated operating revenues for the three months ended September 30, 2003 increased $1,253 million to $3,752 million, from $2,499 million for the same period in 2002. This change was driven by a $1,331 million increase in Sales of Natural Gas and Petroleum Products, due primarily to an increase at Field Services related to improved commodity pricing, and an increase at DENA due primarily to the adoption of the final consensus on 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. As of that date, the Company began to report revenues and expenses for certain derivative and non-derivative 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.

Consolidated operating revenues for the nine months ended September 30, 2003 increased $4,830 million to $11,936 million, from $7,106 million for the same period in 2002. The change was driven by a $4,792 million increase in Sales of Natural Gas and Petroleum Products, due primarily to an increase at Field Services related to increased commodity pricing, and an increase at DENA due primarily to 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 nine months ended September 30, 2003, compared to the same periods in 2002, were driven by primarily 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 (Loss) Gain on Sales of Other Assets, net

Consolidated (loss) gain on sales of other assets, net was a loss of $105 million for the three months September 30, 2003 and a loss of $4 million for the three months ended September 30, 2002. For the nine months ended September 30, 2003, it was a loss of $78 million and for the nine months ended September 30, 2002, it was a loss of $3 million. Amounts for 2003 included losses recorded in the third quarter related to the agreement to sell a 25% undivided interest in the wholly-owned Duke Energy Vermillion facility ($18 million), plans to dispose of stored turbines and related equipment ($66 million) and the pending sale of the remainder of the portfolio of Duke Capital Partners, LLC (DCP) ($23 million). Amounts related to the first six months of 2003 included a $26 million gain resulting from the sales of two groups of assets by Field Services.

In addition to the assets classified as held for sale as of September 30, 2003, the Company continues to assess market conditions as well as opportunities to dispose of certain of its other assets. In accordance with the standards of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” management uses a probability-weighted approach in assessing whether the future cash flows are anticipated to cover an asset’s carrying amount for assets in which dispositions are being considered. Changes to the assumed probability weighting for these assets, based on management’s intent or actual future disposals at sell prices below carrying values, could result in future impairment charges.

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Consolidated Operating Income

Consolidated operating income for the three months ended September 30, 2003 decreased $164 million to a loss of $87 million, from income of $77 million for the same period in 2002. Lower operating income was driven by decreased operating income at DENA of $301 million, due primarily to a write-off of goodwill in 2003, lower spark spreads, and write-downs on certain assets held for sale. These impacts were offset by 2002 charges related to turbine write-downs, site development cost write-offs, demobilization costs, severance costs and a partial impairment on a merchant plant. Partially offsetting the decrease at DENA was an increase in International Energy’s 2003 operating income of $100 million, due primarily to charges recorded in the third quarter of 2002 as a result of the write-off of site development costs and the write-down of uninstalled turbines. Also offsetting the decreases was a $55 million increase in Field Services’ operating income, due primarily to 2002 charges related to Field Services’ internal review and reconciliations of balance sheet accounts, and increased commodity prices offset by related hedging activity.

For the nine months ended September 30, 2003, consolidated operating income increased $45 million to $960 million, from $915 million for the same period in 2002. Lower operating income was driven by decreased operating income at DENA of $446 million, due primarily to the third quarter items described above, and higher earnings in 2002 related to the appreciation of the fair value of the mark-to-market portfolio and the release of incentive accruals. Partially offsetting the decreases at DENA was an increase in Natural Gas Transmission’s operating income of $179 million, driven by two additional months of transportation, storage and distribution income from assets acquired or consolidated as part of the Westcoast acquisition. Also offsetting the decreases was a $157 million increase in International Energy’s operating income, due primarily to the third quarter items described above as well as positive results in the European operations and cost reduction efforts in 2003. Additionally, Field Services’ operating income increased $112 million, due primarily to charges in 2002 related to Field Services’ internal review and reconciliations of balance sheet accounts, and increased commodity prices offset by related hedging activity.

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

Consolidated Earnings before Interest and Taxes (EBIT)

Consolidated EBIT decreased $174 million for the three months and increased $171 million for the nine months ended September 30, 2003, compared to the same periods in 2002. Changes in consolidated EBIT for both the three and nine months ended September 30, 2003 were driven by the same changes as consolidated operating income, as discussed above. The only exception is that consolidated EBIT includes Other Income and Expenses, which decreased $10 million for the three months and increased $126 million for the nine months ended September 30, 2003. The increase for the nine months was driven primarily by DENA’s $178 million gain on the sale of its 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) in June 2003 and Natural Gas Transmission’s $75 million gain on sale of various investments, offset by foregone earnings from investments that were sold.

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). However, the Company includes 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

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third-party interest income on those balances, are generally excluded from the segments’ EBIT. Management believes EBIT is 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 a performance measure and represents the combination of operating income, and other income and expenses, as presented on the Consolidated Statements of Income. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and the Company believes its investors use EBIT as a supplemental measure to evaluate the Company’s consolidated results of operations.

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

Reconciliation of Operating Income and EBIT to Net Income (in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Operating (loss) income	$	(87	)	$	77		$	960		$	915
Other income and expensesa		96			106			443			317
EBIT		9			183			1,403			1,232
Interest expense		293			256			843			613
Minority interest (benefit) expense		(10	)		3			80			76
(Loss) earnings before income taxes		(274	)		(76	)		480			543
Income tax (benefit) expense		(168	)		(43	)		82			163
(Loss) income before cumulative effect of change in accounting principles		(106	)		(33	)		398			380
Cumulative effect of change in accounting principles, net of tax and minority interest		—			—			(52	)		—
Net (loss) income	$	(106	)	$	(33	)	$	346		$	380

^a Includes gains on sales 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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Natural Gas Transmission	$	280		$	288		$	1,009		$	867
Field Services		53			23			162			99
Duke Energy North America		(416	)		(123	)		(191	)		47
International Energy		44			(41	)		209			73
Total reportable segment EBIT		(39	)		147			1,189			1,086
Other Operations		38			57			85			163
Other a		(7	)		(32	)		12			(149	)
Total reportable segment and other EBIT		(8	)		172			1,286			1,100
EBIT attributable to:
Minority interest expense (benefit)		5			(7	)		97			49
Third-party interest income		5			21			10			69
Foreign currency remeasurement gain (loss)		7			(3	)		10			14
Consolidated EBIT	$	9		$	183		$	1,403		$	1,232

^a Other primarily includes certain unallocated corporate costs, and elimination of intercompany profits from D/FD’s earnings for energy plants under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

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

Natural Gas Transmission

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except where noted)	2003		2002		2003		2002
Operating revenues	$	641	$	628	$	2,301	$	1,699
Operating expenses		393		375		1,381		954
Gain on sales of other assets, net		3		—		4		—
Operating income		251		253		924		745
Other income, net of expenses		38		44		117		143
Minority interest expense		9		9		32		21
EBIT	$	280	$	288	$	1,009	$	867
Proportional throughput, TBtu a		679		802		2,502		2,177

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

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

Operating Revenues.Operating revenues for the three months ended September 30, 2003 increased $13 million to $641 million, from $628 million for the same period in 2002. This increase resulted primarily from $42 million of favorable foreign exchange impacts on revenues from the Canadian operations due to the strengthening Canadian dollar. Additionally, revenues increased slightly from business expansion projects in the U.S. and increased $13 million from recovery of natural gas commodity costs passed through to customers without a mark-up at Union Gas Limited (Union Gas), the Company’s natural gas distribution operations in Ontario. Those increased revenues were partially offset by revenues of $18 million in the third quarter of 2002 from operations that were sold in the fourth quarter of 2002 and in 2003.

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Operating Expenses. Operating expenses for the three months ended September 30, 2003 increased $18 million to $393 million, from $375 million for the same period in 2002. This increase was due primarily to $32 million of foreign exchange impacts on the Canadian operating expenses, $15 million of increased natural gas prices at Union Gas and $18 million of severance charges in the third quarter of 2003. Those increases were offset by decreased operating expenses of $12 million from operations sold in the fourth quarter of 2002 and during 2003.

EBIT. For the three months ended September 30, 2003, EBIT decreased $8 million, compared to the same period in 2002. This decrease resulted primarily from 2003 severance charges and foregone earnings on investments sold in 2002.

Nine Months Ended September 30, 2003 as Compared to September 30, 2002

Operating Revenues.Operating revenues for the nine months ended September 30, 2003 increased $602 million to $2,301 million, from $1,699 million for the same period in 2002. This increase resulted primarily from transportation, storage and distribution revenue of $466 million in January and February 2003, from assets acquired or consolidated as 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 $91 million. Additionally, revenues increased $24 million from business expansion projects in the U.S. and $44 million from recovery of natural gas commodity costs passed through to customers without a mark-up at Union Gas. Those increases were partially offset by revenues of $48 million in 2002 from operations sold in the fourth quarter of 2002 and in 2003.

Operating Expenses.Operating expenses for the nine months ended September 30, 2003 increased $427 million to $1,381 million, from $954 million for the same period in 2002. This increase resulted primarily from transportation, storage, and distribution expenses of $319 million in January and February 2003, from assets acquired or consolidated as part of the Westcoast acquisition in March 2002. The increase in expenses was also caused by foreign exchange impacts of $67 million, increased costs of $46 million related to increased natural gas prices at Union Gas and 2003 severance charges of $18 million. Those increases were partially offset by decreased operating expenses of $30 million from operations sold in the fourth quarter of 2002 and during 2003.

For the nine months ended September 30, 2003, Natural Gas Transmission’s operating expenses increased approximately 45%, compared to the same period in 2002, while operating revenues increased approximately 35%. The difference was due to the Westcoast operations acquired in March 2002. The operating expenses, as a percentage of operating revenues, of the acquired Westcoast natural gas distribution business, are greater than the previously owned natural gas transmission business. Gas commodity costs related to the Westcoast distribution business are recovered from customers by increasing revenues by the amount of gas commodity costs expensed (i.e. flowed through to customers with no incremental profit).

Other Income, net of expenses.Other income, net of expenses decreased $26 million for the nine months ended September 30, 2003, compared to the same period in 2002. Gains of $75 million were recognized in the 2003 period on the sale of various assets, including Natural Gas Transmission’s limited partnership interests in Northern Borders Partners L.P. in January 2003, its investment in the Alliance Pipeline and the associated Aux Sable liquids plant in April 2003, and its investment in Foothills Pipe Lines Ltd. in August 2003 (see Note 3 to the Consolidated Financial Statements for information on dispositions). Those gains were partially offset by $24 million of lower equity earnings associated with those investments, and a $27 million construction fee from an affiliate related to the successful completion of the Gulfstream project in the second quarter of 2002. In addition, 2002 included a $32 million gain from the sales of limited partnership interests in Northern Borders Partners L.P. Foreign exchange also negatively impacted other income by $20 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 nine months ended September 30, 2003, compared to the same period in 2002. This resulted from the recognition of a full nine months of minority interest expense in 2003, versus only seven months during the first nine months of 2002, from less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast.

EBIT. For the nine months ended September 30, 2003, EBIT increased $142 million, compared to the same period in 2002, due primarily to incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast, gains on asset sales, and business expansion projects in the U.S., partially offset by earnings in 2002 from operations that were sold in the fourth quarter of 2002 and during 2003, and 2003 severance charges.

Field Services

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except where noted)	2003		2002		2003		2002
Operating revenues	$	1,841	$	1,318	$	6,218	$	3,828
Operating expenses		1,772		1,303		6,040		3,735
Gain on sales of other assets, net		1		—		27		—
Operating income		70		15		205		93
Other income, net of expenses		14		16		53		35
Minority interest expense		31		8		96		29
EBIT	$	53	$	23	$	162	$	99
Natural gas gathered and processed/transported, TBtu/da		7.7		8.4		7.9		8.4
Natural gas liquid (NGL) production, MBbl/db		366.2		395.1		367.6		392.0
Average natural gas price per MMBtuc	$	4.97	$	3.18	$	5.66	$	2.97
Average NGL price per gallond	$	0.49	$	0.39	$	0.52	$	0.36

^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 September 30, 2003 as Compared to September 30, 2002

Operating Revenues.Operating revenues for the three months ended September 30, 2003 increased $523 million to $1,841 million, from $1,318 million for the same period in 2002. The increase was driven primarily by a $0.10 per gallon increase in average NGL prices and a $1.79 per MMBtu increase in average natural gas prices, offset by results of related hedging activity of approximately $36 million.

Operating Expenses.Operating expenses for the three months ended September 30, 2003 increased $469 million to $1,772 million, from $1,303 million for the same period in 2002. The increase was due primarily to a $0.10 per gallon increase in average NGL prices, and a $1.79 per MMBtu increase in average natural gas prices. Partially offsetting the commodity price increases were charges of approximately $32 million during the third quarter of 2002 for reserves for gas imbalances with suppliers and customers, and other charges related to Field Services’ internal review and reconciliations of balance sheet accounts.

Minority Interest Expense. Minority interest expense increased $23 million for the three months ended September 30, 2003, compared to the same period in 2002. The increase was due primarily 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.

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EBIT.The $30 million increase in EBIT was largely the result of higher average NGL prices, offset by higher average natural gas prices, related hedging activity and increased operating expenses, as discussed above. In the third quarter of 2002, results were negatively impacted by $22 million (net of minority interest expense) due to increased reserves primarily related to imbalances with customers and suppliers, and other charges related to Field Services’ internal review and reconciliations of balance sheet accounts.

Nine months Ended September 30, 2003 as Compared to September 30, 2002

Operating Revenues.Operating revenues for the nine months ended September 30, 2003 increased $2,390 million to $6,218 million, from $3,828 million for the same period in 2002. The increase was driven primarily by a $0.16 per gallon increase in average NGL prices and a $2.69 per MMBtu increase in average natural gas prices, offset by related hedging activity of approximately $171 million. This net increase was partially offset by lower trading and marketing net margin of $43 million, due primarily to declines in natural gas and NGL trading activity. Offsetting the decrease in trading and marketing net margin was an approximate $23 million increase related to physical natural gas marketing activity. Prior to January 1, 2003, that activity was recorded in trading and marketing net margin within Other Operating Revenues but it is now presented on a gross basis in revenues and expenses in accordance with EITF Issue No. 02-03.

Operating Expenses.Operating expenses for the nine months ended September 30, 2003 increased $2,305 million to $6,040 million, from $3,735 million for the same period in 2002. The increase was due primarily to a $0.16 per gallon increase in average NGL prices, and a $2.69 per MMBtu increase in average natural gas prices. Also contributing to the increase were higher operating, maintenance, corporate overhead and depreciation costs of approximately $25 million due primarily to increased maintenance, repairs and capital expenditures. Offsetting those increases were charges of approximately $48 million during the second and third quarters of 2002 due to increased reserves primarily related to imbalances with customers and suppliers, a storage inventory write-down charge, and other charges related to Field Services’ internal review and reconciliations of balance sheet accounts.

Gain on Sales of Other Assets, net. The $27 million gain on sales of other assets in 2003 related to the sale of one group of assets to Crosstex Energy Services, L.P. (Crosstex) and a second group of assets to ScissorTail Energy, LLC (ScissorTail).

Other Income, net of expenses.Other income, net of expenses increased $18 million for the nine months ended September 30, 2003, compared to the same period in 2002. This increase was due to an $11 million gain on the sale of Class B units of TEPPCO Partners, L.P. (TEPPCO) and an $8 million increase in equity earnings of the general partner interest in 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 increased $67 million for the nine months ended September 30, 2003, compared to the same period in 2002. This increase was due to increased earnings from DEFS. The increase in minority interest expense was not proportionate to the increase in Field Services’ earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Company’s corporate level that are not included in DEFS.

EBIT.The $63 million increase in EBIT was largely the result of higher average NGL prices, offset by higher average 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 $19 million gain on the sale of assets (net of minority interest expense) and the $11 million gain on the sale of the TEPPCO units. The 2002 results were negatively impacted by $34 million (net of minority interest expense) due to increased reserves primarily related to imbalances with customers and suppliers, a storage inventory write-down charge, and other charges related to Field Services’ internal review and reconciliations of balance sheet accounts.

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Field Services expects to record approximately $8 million (net of minority interest expense) in severance costs in the fourth quarter of 2003.

Duke Energy North America

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except where noted)	2003			2002			2003			2002
Operating revenues	$	964		$	484		$	2,969		$	1,069
Operating expenses		1,345			648			3,328			1,066
Loss on sales of other assets, net		(84	)		—			(84	)		—
Operating (loss) income		(465	)		(164	)		(443	)		3
Other income, net of expenses		11			13			207			29
Minority interest benefit		(38	)		(28	)		(45	)		(15	)
EBIT	$	(416	)	$	(123	)	$	(191	)	$	47
Actual plant production, GWha, b		9,130			9,662			18,750			19,188
Proportional megawatt capacity in operation								15,836			14,211

^a Gigawatt-hours

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

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

Operating Revenues. Operating revenues for the three months ended September 30, 2003 increased $480 million to $964 million, from $484 million for the same period in 2002. Revenues increased $573 million with the January 1, 2003 implementation of the remaining provisions of EITF Issue No. 02-03. As a result, 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 Risk Management Activities,” are now reported on a gross basis. Specifically, the $573 million increase was primarily related to the presentation 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 EITF provisions.

Also contributing to increased revenues was a $104 million increase in net trading margin, due to less unfavorable market changes in correlation and volatility in 2003 as compared to 2002. Those increases were partially offset by a $216 million decrease in energy generation revenues, including a $185 million decrease from overall lower power prices realized and a $31 million decrease due to volumes delivered.

Operating Expenses. Operating expenses for the three months ended September 30, 2003 increased $697 million to $1,345 million, from $648 million for the same period in 2002. Similar to the increase in operating revenues discussed above, operating expenses increased $573 million due to the adoption of the final consensus on EITF Issue No. 02-03. Operating expenses also increased $80 million due to increased charges and write-offs recorded in 2003. The charges and write-offs recorded in the third quarter of 2003 included the write-off of $254 million of goodwill, primarily related to the formation of DENA’s trading and marketing business (see Note 2 to the Consolidated Financial Statements); a $28 million (before minority interest) CFTC settlement (see Note 11 to the Consolidated Financial Statements); and severance costs of $5 million. The charges and write-offs recorded in the third quarter 2002 included provisions for

44

the termination of certain turbines on order and write-down of other uninstalled turbines of $121 million, the write-off of site development costs primarily in California of $31 million, demobilization costs related to the deferral of three merchant power projects of $12 million, partial impairment of a merchant plant of $31 million and severance costs of $12 million. In addition, the third quarter of 2003 included $20 million of increased operating and maintenance costs and depreciation associated with projects that entered into commercial operations after the third quarter of 2002.

Loss on Sales of Other Assets, net.Loss on sales of other assets for the three months ended September 30, 2003 was $84 million, due to the write-downs of the 25% undivided interest to be sold in DENA’s Vermillion plant and uninstalled turbines and other equipment to their estimated fair values (see Note 3 to the Consolidated Financial Statements).

Minority Interest Benefit. For the three months ended September 30, 2003 and September 30, 2002, 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. DETM’s lower results were due to a reduction in mark-to-market earnings.

EBIT. For the three months ended September 30, 2003, EBIT decreased $293 million, compared to the same period in 2002. The decrease was driven primarily by the write-off of goodwill in 2003 and lower spark spreads.

Nine Months Ended September 30, 2003 as Compared to September 30, 2002

Operating Revenues. Operating revenues for the nine months ended September 30, 2003 increased $1,900 million to $2,969 million, from $1,069 million for the same period in 2002. Revenues increased $1,984 million due to the adoption of EITF Issue No. 02-03, as discussed above. Also contributing to the increase was a $148 million increase in net trading margin. This increase was driven primarily by less unfavorable market changes in correlation and volatility in 2003 as compared to 2002, partially offset by a $76 million increase in 2002 from the appreciation 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. Offsetting those increases was a $247 million decrease in energy generation revenues, due to a $221 million decrease from overall lower power prices realized and a $26 million decrease due to volumes delivered.

Operating Expenses. Operating expenses for the nine months ended September 30, 2003 increased $2,262 million to $3,328 million, from $1,066 million for the same period in 2002. Similar to the increase in operating revenues described above, operating expenses increased $1,984 million due to the adoption of the final consensus on EITF Issue No. 02-03. Operating expenses also increased $80 million due to increased charges and write-offs recorded in 2003, as discussed above. The release of $89 million of incentive accruals in 2002 also contributed to increased operating expenses in the current year. In addition, 2003 included $80 million of increased operating and maintenance costs, and depreciation associated with projects that entered into commercial operations during 2002 and 2003.

Loss on Sales of Other Assets, net.Loss on sales of other assets for the nine months ended September 30, 2003 was $84 million due to the write-downs of the 25% undivided interest to be sold in DENA’s Vermillion plant and uninstalled turbines and other equipment to their estimated fair values (see Note 3 to the Consolidated Financial Statements).

Other Income, net of expenses. Other income, net of expenses increased $178 million for the nine months ended September 30, 2003, compared to the same period in 2002. The increase was due to the sale of DENA’s 50% ownership interest in Ref-Fuel to Highstar Renewable Fuels LLC for a gain of approximately $178 million in 2003.

Minority Interest Benefit. For the nine months ended September 30, 2003 and September 30, 2002, losses at DETM resulted in a minority interest benefit. DETM’s lower results were due to a reduction in mark-to-market earnings.

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EBIT. For the nine months ended September 30, 2003, EBIT decreased $238 million, compared to the same period in 2002, due primarily to the write-off of goodwill in 2003, lower spark spreads, write-downs in 2003 for certain assets held for sale, and increases in 2002 related to the appreciation of the fair value of the mark-to-market portfolio. Those decreases were offset slightly by the 2003 gain on the sale of Ref-Fuel.

International Energy

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except where noted)	2003			2002			2003			2002
Operating revenues	$	295		$	203		$	1,043		$	711
Operating expenses		256			265			853			679
Loss on sales of other assets, net		(1	)		—			(1	)		—
Operating income (loss)		38			(62	)		189			32
Other income, net of expenses		9			26			33			57
Minority interest expense		3			5			13			16
EBIT	$	44		$	(41	)	$	209		$	73
Sales, GWh		4,301			5,637			14,378			15,583
Proportional megawatt capacity in operation								4,585			4,825
Proportional maximum pipeline capacity in operation, MMcf/da								363			363

^a Million cubic feet per day

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

Operating Revenues. Operating revenues for the three months ended September 30, 2003 increased $92 million to $295 million, from $203 million for the same period in 2002. Of this increase, $102 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 EITF provisions.

Also contributing to the increase in 2003 were revenues of $14 million from favorable recontracted capacity in Brazil, revenues of $13 million from an 80 megawatt plant in Guatemala that began commercial operations in 2003, a $13 million increase from foreign currency valuations in Brazil and Argentina, and a $10 million increase from improved gas marketing margins in Europe. Those increases were partially offset by $24 million of foregone revenues due to the sale of International Energy’s 85.7% majority interest in P.T. Puncakjaya Power (PJP) in July 2003 (see Note 3 to the Consolidated Financial Statements), a decrease of $17 million due to lower natural gas sales volumes caused by the early termination of a natural gas sales contract and a decrease of $16 million from a contract termination in El Salvador.

Operating Expenses. Operating expenses for the three months ended September 30, 2003 decreased $9 million to $256 million, from $265 million for the same period in 2002. The decrease was due to $91 million of charges recorded in the third quarter of 2002, as a result of the write-off of site-development costs and the write-down of uninstalled turbines, primarily related to planned energy plants in Brazil; $12 million in lower gas purchases, due to the early termination of a natural gas sales contract; and $11 million due to foregone expenses due to the sale of PJP. Those decreases were partially offset by a $102 million increase in operating expenses caused by the adoption of the final consensus on EITF Issue No. 02-03.

Other Income, net of expenses. Other income, net of expenses decreased $17 million for the three months ended September 30, 2003, compared to the same period in 2002. Of this decrease, $11 million was due to

46

the timing of revenue recognition and increased downtime at the Cantarell equity investment in Mexico, a nitrogen production plant acquired with Westcoast. Also contributing to the decrease was a $7 million charge in Brazil to correct an environmental reserve credited to income in 2001. Since the impact to prior year’s financial statement was not material, International Energy recorded an out of period expense in the third quarter of 2003 to correct the treatment of this item.

EBIT. For the three months ended September 30, 2003, EBIT increased $85 million, compared to the same period in 2002. The increase was attributable to $91 million of charges recorded in the third quarter of 2002, as discussed above; $14 million of favorable recontracted capacity within Brazil; and $10 million from improved gas marketing margins in Europe. Those increases were offset by a $13 million decrease due to the foregone earnings and loss on the sale of PJP, and $11 million of lower equity earnings in Mexico.

Nine Months Ended September 30, 2003 as Compared to September 30, 2002

Operating Revenues. Operating revenues for the nine months ended September 30, 2003 increased $332 million to $1,043 million, from $711 million for the same period in 2002. Of this increase, $375 million was due to the adoption of EITF Issue No. 02-03, as discussed above. Also contributing to the increase were improved gas marketing margins in Europe of $30 million; revenues of $24 million from assets acquired in France during the third quarter of 2002; revenues of $23 million in 2003 from favorable recontracted capacity in Brazil; a $19 million increase in electric and transportation revenues in Asia Pacific; revenues of $13 million from an 80 megawatt plant in Guatemala that began commercial operations in 2003; an $11 million adjustment to revenues and receivables during the second quarter of 2003 as a result of a regulatory audit in Brazil; and revenues of $7 million from increased generation and $2 million from increased energy prices for International Energy’s Latin American operations. Those 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, $24 million of foregone revenues due to the sale of PJP, $23 million due to changes in timing of revenue recognition within PJP in 2003, $16 million due to a contract termination by a counterparty in El Salvador, $11 million due to lower natural gas volumes within the liquefied natural gas (LNG) line of business caused by the early termination of a natural gas sales contract, and a $7 million decrease from foreign currency valuations within Brazil and Argentina.

Operating Expenses. Operating expenses for the nine months ended September 30, 2003 increased $174 million to $853 million, from $679 million for the same period in 2002. Similar to the increase in operating revenues described above, operating expenses increased $375 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; $12 million due to an 80 megawatt plant in Guatemala that began commercial operations in 2003; and $10 million from increased generation and $4 million from increased prices in International Energy’s Latin American operations. Those 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; $91 million of charges in the third quarter of 2002, as a result of the write-off of site-development costs and the write-down of uninstalled turbines, primarily related to planned energy plants in Brazil; $26 million due to lower natural gas purchases and a reduction in estimated probable losses within the LNG line of business, due to the early termination of a natural gas sales contract; $25 million of cost reduction efforts; and $11 million of foregone expenses due to the sale of PJP.

Other Income, net of expenses. Other income, net of expenses decreased $24 million for the nine months ended September 30, 2003, compared to the same period in 2002. Of this decrease, $34 million was due to the timing of revenue recognition at the Cantarell equity investment in Mexico, a nitrogen production plant acquired with Westcoast. Also contributing to the decrease was the $7 million charge in the third quarter of 2003 related to prior years’ environmental reserves. Those decreases were offset by $12 million of favorable earnings for National Methanol Company, another equity owned investment, due to favorable product prices.

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EBIT. For the nine months ended September 30, 2003, EBIT increased $136 million, compared to the same period in 2002. The increase was primarily attributable to the $91 million of charges recorded in the third quarter of 2002; $30 million of improved gas marketing margins and decreased costs in Europe; a $19 million adjustment from the regulatory audit in Brazil; $25 million in cost reduction efforts; and $18 million from a reduction in estimated losses within the LNG line of business, due to the early termination of a natural gas sales contract. EBIT also increased as a result of $13 million in increased equity earnings related to National Methanol Company, driven by favorable product prices. Those increases were partially offset by a $30 million decrease related to the timing of revenue recognition, $22 million of which relates to a charge related to the timing of revenue recognition at the Cantarell equity investment in Mexico; a $16 million decrease from currency valuations; and a $13 million decrease related to foregone EBIT and loss on the sale of PJP.

Other Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2003			2002			2003			2002
Operating revenues	$	166		$	121		$	425		$	432
Operating expenses		119			97			361			362
Loss on sales of other assets, net		(23	)		(4	)		(23	)		(3	)
Operating income		24			20			41			67
Other income, net of expenses		14			36			45			94
Minority interest (benefit) expense		—			(1	)		1			(2	)
EBIT	$	38		$	57		$	85		$	163

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

Operating Revenues.Operating revenues for the three months ended September 30, 2003 increased $45 million to $166 million, from $121 million for the same period in 2002. The increase was related to $45 million of increased revenues at Crescent Resources, LLC (Crescent), due primarily to increased revenues from land sales and trades, and commercial project sales.

Operating Expenses. Operating expenses for the three months ended September 30, 2003 increased $22 million to $119 million, from $97 million for the same period in 2002. The increase was due primarily to $19 million of increased expenses at Crescent, due primarily to increased costs related to residential and commercial project sales.

Loss on Sales of Other Assets, net. Loss on sales of other assets for the three months ended September 30, 2003 changed $19 million to a loss of $23 million from a loss of $4 million for the same period in 2002. The change was due primarily to the write-down of investments held for sale at DCP (see Note 3 to the Consolidated Financial Statements).

Other Income, net of expenses.Other income, net of expenses decreased $22 million for the three months ended September 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. Therefore, the related intercompany profit was eliminated within the Other group.

EBIT. For the three months ended September 30, 2003, EBIT decreased $19 million, compared to the same period in 2002. As discussed above, the decline in EBIT was primarily driven by fewer plant completions by D/FD in 2003 and the write-down of investments held for sale at DCP. Those decreases were partially offset by improved results at Crescent.

Nine Months Ended September 30, 2003 as Compared to September 30, 2002

Operating Revenues.Operating revenues for the nine months ended September 30, 2003 decreased $7 million to $425 million, from $432 million for the same period in 2002. The decrease was due primarily to

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the sale of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) in 2002; those businesses contributed $162 million to revenues during the first nine months of 2002. Offsetting that decrease was a $93 million increase in revenues at Crescent, due primarily to the sale of a multifamily project in June 2003 and increased revenues from residential projects, and a $52 million increase in revenues at Energy Delivery Services (EDS), as a result of EDS beginning operations in May 2002 and thus not recognizing a full nine months of operations in the prior year.

Operating Expenses. Operating expenses for the nine months ended September 30, 2003 decreased $1 million to $361 million, from $362 million for the same period in 2002. The decrease was due primarily to the sale of DE&S and DukeSolutions in 2002, as these businesses contributed $164 million to expenses during the first nine months of 2002. Offsetting this decrease was a $70 million increase in expenses at Crescent, due primarily to the cost of a multifamily project sale and an increase in the cost of residential project sales; increased expenses at EDS of $53 million, as a result of EDS beginning operations in May of 2002 and thus not recognizing a full nine months of operations in the prior year; and a $14 million increase in expenses at DCP, due to 2003 wind-down costs, including the write-down of investments caused by a permanent reduction in the value of its loan portfolio.

Loss on Sales of Other Assets, net. Loss on sales of other assets for the nine months ended September 30, 2003 changed $20 million, to a loss of $23 million from a loss of $3 million for the same period in 2002. The change was due primarily to a $23 million write-down of investments held for sale at DCP in 2003 (see Note 3 to the Consolidated Income Statements).

Other Income, net of expenses.Other income, net of expenses decreased $49 million for the nine months ended September 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. Therefore, the related intercompany profit was eliminated within the Other group.

EBIT. For the nine months ended September 30, 2003, EBIT decreased $78 million, compared to the same period in 2002. As discussed above, the decline in EBIT was primarily driven by the $20 million decrease due to the sale of assets and the $49 million decrease in other income due primarily to the D/FD business. Also contributing to the decline in EBIT were write-downs at DCP in 2003, partially offset by improved results from Crescent.

Other

For the three months ended September 30, 2003, EBIT for Other improved $25 million to a loss of $7 million, from a loss of $32 million for the same period in 2002. For the nine months ended September 30, 2003, it improved $161 million to income of $12 million, from a loss of $149 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. Those intercompany profits are primarily a result of D/FD’s earnings for energy plants under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

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Other Impacts on Net Income

Interest expense increased $37 million for the three months September 30, 2003, compared to the same period in 2002. The increase was due primarily to a $33 million decrease in capitalized interest, resulting primarily from DENA’s significantly lower plant construction activity in 2003.

For the nine months ended September 30, 2003, interest expense increased $230 million, compared to the same period in 2002. The increase was due primarily to a $121 million decrease in capitalized interest, resulting mainly from lower capitalized interest for DENA. The remaining increase was due primarily to higher debt balances, resulting mainly from debt assumed in, and issued with respect to, the acquisition of Westcoast.

Minority interest expense decreased $13 million for the three months and increased $4 million for the nine months ended September 30, 2003, compared to the same periods in 2002. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of the Company. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No.150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” As a result of this accounting change and due to lower distributions related to Catawba River Associates, LLC (changes in its ownership structure as of October 2002 caused costs associated with this financing to be classified as interest expense from minority interest), minority interest expense decreased $23 million for the three months and $38 million for the nine months ended September 30, 2003.

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 $10 million for the three months and $42 million for the nine months ended September 30, 2003, compared to the same periods for 2002. The 2003 increases were driven by increased earnings from DEFS and from recognizing a full nine months of minority interest expense in 2003, versus only six months during 2002, from less than wholly owned subsidiaries acquired in the March 2002 acquisition of Westcoast. Those increases were partially offset by decreased earnings at DETM.

Income tax benefit increased approximately $125 million for the three months ending September 30, 2003, compared to the same period in 2002. For the nine months ending September 30, 2003, income tax expense decreased $81 million, compared to the same period in 2002. The primary driver for the change in both periods was a $52 million tax benefit recorded in the third quarter of 2003 related to the goodwill impairment recognized in 2002 for the gas trading business in Europe and lower earnings.

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. 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, “Accounting for Asset Retirement Obligations” (see Note 2 to the Consolidated Financial Statements).

LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2003, the Company had $1,209 million in cash and cash equivalents compared to $814 million as of December 31, 2002. The Company’s working capital was a $574 million surplus as of September 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.

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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 counterparties. 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. While the Company has the 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 $1,140 million for the nine months ended September 30, 2003 when compared to the same period in 2002. The decrease in cash provided by operating activities was due primarily to changes in working capital for the comparable period and lower cash settlements from trading and hedging activities.

Investing Cash Flows

Net cash provided by investing activities increased $5,243 million for the nine months ended September 30, 2003 when compared to the same period in 2002. Capital and investment expenditures decreased $3,936 million for the nine months ended September 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 decreased in 2003 compared to 2002, due primarily to reduced investments at Other Operations (primarily related to DCP) and Natural Gas Transmission’s 2002 investment in a 50% interest in Gulfstream. Increased proceeds of $1,213 million from sales of equity investments and other assets also contributed to the decrease in net cash used in investing activities. The increased proceeds in 2003 were due primarily to the sale of DENA’s 50% ownership interest in Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline and sale of its investments in the Alliance Pipeline and the associated Aux Sable liquids plant and the sale of Foothills Pipe Lines Ltd.; Field Services’ sale of assets to Crosstex and Scissortail and the Company’s sale of TEPPCO class B units; International Energy’s sale of its 85.7% majority interest in PJP; and the monetization of certain investments at DCP. The Company expects to generate an additional $230 million of proceeds from sales announced to date of certain equity investments and other assets in the fourth quarter of 2003.

Financing Cash Flows and Liquidity

Cash flows from financing activities decreased $3,813 million to net cash used in financing activities of $1,314 million for the nine months ended September 30, 2003 from net cash provided by financing activities of $2,499 million for the nine months ended September 30, 2002. This change is due primarily to the net reduction of outstanding long-term debt, trust preferred securities, and notes payable and commercial paper during the first nine months of 2003 as compared to the same period in 2002 when the Company acquired Westcoast and financed other business expansion projects. Additionally, this change in cash flows from financing activities is aligned with the Company’s strategy to reduce outstanding debt. The Company also received over $1 billion in capital infusions from Duke Energy in 2003.

The Company’s cash requirements throughout the first nine months of 2003 have been funded by cash from operations and the sale of assets. Cash from operations and the sale of assets has been adequate for funding capital expenditures and repaying debt and trust preferred securities. For the remainder of 2003, management expects this trend to continue. During the first 10 months of 2003, the Company has announced or completed asset sales of approximately $2,100 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 PJP. In addition, the Company may access the capital markets depending on market opportunities and other factors.

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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 Facilities and Shelf Registrations. During the nine-month period ended September 30, 2003, the Company, Union Gas, DEFS and Duke Australia Finance Pty Ltd. (a wholly owned subsidiary of the Company) replaced portions of their 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 September 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 September 30, 2003(in millions)

	Expiration Date	Credit Facilities Available		Amounts Outstanding
				Commercial Paper		Letters of Credit		Other Borrowings		Total
Duke Capital Corporation
$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		$	1,341	$	209	$	519	$	—	$	728
Westcoast Energy Inc.
$185 364-day syndicateda, b, d	December 2003
$148 two-year syndicatedb, e	December 2004
Total Westcoast Energy Inc.			333		—		—		—		—
Union Gas Limited
$252 364-day syndicateda, f	July 2004		252		—		—		—		—
Duke Energy Field Services, LLC
$350 364-day syndicateda, c, g	March 2004		350		—		—		—		—
Duke Australia Finance Pty Ltd.
$216 364-day syndicatedh	March 2004		216		134		—		64		198
Duke Australia Pipeline Finance Pty Ltd.
$213 multi-year syndicatedi	February 2005		213		—		—		193		193
Totalj		$	2,705	$	343	$	519	$	257	$	1,119

^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 facility is denominated in Canadian dollars, and was 250 million Canadian dollars as of September 30, 2003. Subsequent to September 30, 2003, the credit facility was reduced to 200 million Canadian dollars and the expiration date of the credit facility was extended to July 2004.

^e Credit facility is denominated in Canadian dollars, and was 200 million Canadian dollars as of September 30, 2003. Subsequent to September 30, 2003, the credit facility was reduced to 100 million Canadian dollars and the expiration date of the credit facility was extended to July 2005.

^f Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. In addition, this credit facility contains an option allowing it to be converted to a one-year term loan upon its expiration. Credit facility is denominated in Canadian dollars, and was 340 million Canadian dollars as of September 30, 2003.

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

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

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

^j Various operating credit facilities and credit facilities that support commodity, foreign exchange, derivative and intra-day transactions are not included in this credit facilities summary.

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

The Company may be required to repay certain debt should their credit ratings fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investor Service (Moody’s). 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 September 30, 2003, the Company had effective SEC shelf registrations for up to $1,000 million in gross proceeds from debt and other securities. Additionally, as of September 30, 2003, the Company had access to 200 million Canadian dollars (U.S. $148 million) available under Canadian shelf registrations for issuances in the Canadian market. During the third quarter of 2003, the shelf registration for 750 million Canadian dollars expired. Subsequent to September 30, 2003, this shelf registration was renewed for 500 million Canadian dollars. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 200 million Canadian dollars will expire in June 2004 and 500 million Canadian dollars will expire in November 2005.

For a discussion of the Company’s significant financing activities, see Notes 8 and 9 to the Consolidated Financial Statements.

Credit Ratings. In March 2003, 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 rating 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. In September 2003, Moody’s confirmed its long and short-term ratings of DEFS and placed DEFS on Stable Outlook, concluding its Review for Potential Downgrade.

In June 2003, 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 one ratings level. 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.

In September 2003, Fitch Ratings (Fitch) lowered its long-term ratings of the Company, PanEnergy, and Texas Eastern one ratings level, and its short-term rating of the Company one ratings level. Fitch’s actions were based on concerns about the Company’s merchant energy exposure at DENA and substandard investment returns on international energy operations. Fitch concluded its actions by leaving the Company, PanEnergy, and Texas Eastern on Negative Outlook.

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The following table summarizes the September 30, 2003 credit ratings from rating agencies retained by the Company to rate the Company, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of September 30, 2003

	Standard and Poors		Moody’s Investor Service	Fitch Ratings	Dominion Bond Rating Service (DBRS)
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	Ad
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

^d In August 2003, DBRS initiated a rating on Maritimes & Northeast Pipeline, LLC at the Company’s request.

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 materially 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, through trading and marketing and other contracts on behalf of DENA or otherwise.

A reduction in DETM’s credit rating to below investment grade as of September 30, 2003 would have resulted in the posting of additional collateral of up to approximately $240 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.

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).”

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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. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment of FASB Statement No. 123).” In December 2002, the FASB issued SFAS No. 148, which amends SFAS No. 123, and provides alternative methods of transition for a voluntary change to the fair value-based method of accounting for stock-based employee compensation. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” and APB Opinion No. 28, “Interim Financial Reporting,” to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The disclosure provisions of SFAS No. 148 are included in Note 2 to the Consolidated Financial Statements.

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.”In April 2003, the FASB issued SFAS No. 149, which amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities, including the qualifications for the normal purchases and normal sales exception, under SFAS No. 133. 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 are to 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 continue to be applied based upon their original effective dates. The Company adopted the provisions of SFAS No. 149 on July 1, 2003. Certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity led the Company to re-evaluate its policy for accounting for forward sales contracts. As a result, the Company has elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges on a prospective basis. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 will continue to be accounted for under such exception, including following any modifications to these contracts, as long as the requirements for applying the normal purchases and normal sales exception are met.

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 does not anticipate that this Issue 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 has been applied to the Company’s existing financial instruments beginning on July 1, 2003.

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As a result of the adoption of SFAS No. 150, Long-term Debt as of September 30, 2003 includes $600 million of trust preferred securities which had been previously included on the Consolidated Balance Sheet as Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation. Long-term Debt as of September 30, 2003 also includes approximately $23 million of one of the Company’s subsidiary’s preferred and preference stock which had been previously included on the Consolidated Balance Sheet as Minority Interests. In accordance with the requirements of SFAS No. 150, prior period amounts have not been reclassified to be in conformity with the current presentation. See Note 9 to the Consolidated Financial Statements for further discussion of the impact of adoption of SFAS No. 150 on the Company’s trust preferred securities. The Company is still evaluating the impact of the recent discussions held by the FASB related to the application of SFAS No. 150 to non-controlling interests in certain limited life entities, but does not anticipate this will have a material impact on the Company’s consolidated results of operations, cash flows or financial position.

The Company’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited life entities based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3. The Company continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on the Company’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant changes could be made by the FASB during such future deliberations. Therefore, the Company is not able to conclude as to whether such future changes would be likely to materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.

FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary 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 by the first fiscal year or interim period ending after December 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. The Company currently anticipates certain entities, previously accounted for under the equity method of accounting, will be consolidated by the Company as of December 31, 2003 under the provisions of FIN 46. These entities, which are substantive entities, have total assets of approximately $220 million as of September 30, 2003 and total revenue of approximately $110 million for the nine-months ended September 30, 2003. The Company’s maximum exposure to loss as a result of its involvement with these entities is approximately $100 million, generally limited to the Company’s investment and guarantee obligations in these entities as of September 30, 2003. Further, upon adoption of FIN 46, the Company anticipates deconsolidating the trusts that have issued the trust preferred securities, as discussed in Note 9 to the Consolidated Financial Statements, since the Company is not the primary beneficiary of such trusts. This deconsolidation will result in the Company reflecting an affiliate note payable to the trusts, rather than trust preferred securities in the Consolidated Balance Sheets. Additionally, the Company has a significant variable interest in, but is not the primary beneficiary of, Duke COGEMA Stone & Webster, LLC (DCS) due to certain guarantee obligations as discussed in Note 11 to the Consolidated Financial Statements. As further discussed in Note 11 to the Consolidated Financial Statements, the Company’s maximum exposure

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to loss as a result of its variable interest in DCS cannot be quantified. 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. The FASB continues to interpret the provisions of FIN 46 and has issued an exposure draft to amend certain provisions of FIN 46 which is expected to become effective in the fourth quarter of 2003. Until such interpretations and amendments are finalized, the Company is not able to conclude as to whether such future changes would be likely to materially affect its consolidated results of operations, cash flows or financial position.

EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” In May 2003, the EITF reached consensus in EITF Issue No. 01-08 to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The Company has historically provided and leased storage capacity to outside parties as well as entered into pipeline capacity agreements both as the lessee and as a lessor. Upon application of EITF Issue No. 01-08, the accounting requirements under the consensus could affect the timing of revenue and expense recognition, and revenues reported as transportation and storage services may be required to be reported as rental or lease income. Should capital-lease treatment be necessary, purchasers of transportation and storage services in the arrangements would be required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for as transportation and storage purchases or sales arrangements. The Company does not anticipate that the adoption of EITF Issue No. 01-08 will have a material effect 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 and the economic substance of the transaction. In analyzing the facts and circumstances, EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal vs. Net as an Agent,” and Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF Issue No. 03-11 is effective for transactions or arrangements entered into after September 30, 2003. 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.

Subsequent Events

On October 1, 2003, the Company completed the sale of its 30% interest in Vector Pipeline to Enbridge Inc. and DTE Energy Company for $145 million. The Company expects to record the sale during the fourth quarter of 2003. Each company paid $72.5 million for an equal share of the Company’s previous 30% ownership stake. The Vector Pipeline transports Western Canadian natural gas from the Chicago area market hub to the hub at Dawn, Ontario. The Company acquired ownership interest in the pipeline through its 2002 acquisition of Westcoast Energy.

Subsequent to October 31, 2003, management has committed to a plan to sell one of DENA’s merchant power generation facilities. The carrying value of the facility as of September 30, 2003 was approximately $220 million, and the anticipated net sales proceeds are approximately $140 million resulting in a pre-tax loss of approximately $80 million that the Company expects to record in the fourth quarter of 2003. The amount of the loss is subject to the resolution of the completion of certain terms and conditions that may impact the final amount. The sale of the facility is expected to be completed within the next twelve months.

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As of October 31, 2003, management committed to a plan to sell its Dutch-based gas marketing business. The carrying value of this business was approximately $60 million as of September 30, 2003 and the anticipated net sales proceeds are approximately $80 million. The amount of the anticipated gain will depend on the final terms and conditions of the proposed sale and will be recorded at the time of closing, which is expected to occur in the fourth quarter of 2003, subject to approval by the European Commission. In connection with the sale and during the balance of 2003 and 2004, the Company expects to incur expenses of approximately $40 million related to the winding-down of its remaining European gas marketing operations.

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

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 prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. On April 11, 2003, The Company announced that it will be exiting proprietary trading at DENA and International Energy. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.

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 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 its 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 primarily designated and qualify as effective hedge positions of future cash flows, or fair values of the Company’s assets and liabilities.

The carrying value of designated hedges on the Company’s September 30, 2003 Consolidated Balance Sheets is $884 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 Company’s Consolidated Balance Sheets.

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Based on a sensitivity analysis as of September 30, 2003, it was estimated that a difference of one cent per gallon in the average price of NGLs over the next twelve month period would have a corresponding effect on Operating Income of approximately $11 million (at the Company’s 70% ownership of DEFS), after considering the effect of the Company’s commodity hedge positions.

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. To reduce credit risk exposure and mitigate counterparty credit risk, where available, the Company enters into netting agreements with counterparties that permit offset of receivables and payables with such counterparties. 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. The Company has recognized losses through increased credit reserves. While the Company has the processes in place to monitor and attempt to mitigate economic exposure 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 control 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.

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.

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 third 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: November 11, 2003	/s/ Robert P. Brace
	Robert P. Brace Chairman of the Board and President

Date: November 11, 2003	/s/ Keith G. Butler
	Keith G. Butler Controller and Chief Financial Officer

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