DUKE CAPITAL CORP - 10-Q Quarterly Report

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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, 2002

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

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 Registrant’s classes of common stock, as of the latest practicable date.

Number of shares of Common Stock, no par value, outstanding at October 31, 2002

1,010

DUKE CAPITAL CORPORATION

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2002

INDEX

Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements	1
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2002 and 2001	1
	Consolidated Balance Sheets as of September 30, 2002 and December 31, 2001	2
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2002 and 2001	4
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2002 and 2001	5
	Notes to Consolidated Financial Statements	6
2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	21
3.	Quantitative and Qualitative Disclosures about Market Risk	37
4.	Controls and Procedures	44

	PART II. OTHER INFORMATION
1.	Legal Proceedings	45
6.	Exhibits and Reports on Form 8-K	45
	Signatures	46

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 our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside our 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 proceedings or inquiries;

•

industrial, commercial and residential growth in our service territories;

•

the weather and other natural phenomena;

•

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

•

changes in environmental and other laws and regulations to which we and our subsidiaries are subject or other external factors over which we have no control;

•

the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;

•

the level of creditworthiness of counterparties to our transactions;

•

the amount of collateral required to be posted from time to time in our transactions;

•

growth in opportunities for our business units, including the timing and success of efforts to develop domestic and international power, pipeline, gathering, processing and other infrastructure projects;

•

the performance of electric generation, pipeline and gas processing facilities;

•

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

•

the effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described.

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,
	2002			2001		2002			2001
Operating Revenues
Sales of natural gas and petroleum products	$	1,145		$	996	$	3,567		$	6,213
Transportation and storage of natural gas		429			253		1,202			731
Electric generation		841			735		1,805			2,077
Trading and marketing net margin (loss)		(118	)		774		(51	)		1,002
Other		278			612		832			1,260

Total operating revenues		2,575			3,370		7,355			11,283


Operating Expenses
Natural gas and petroleum products purchased		896			1,060		2,797			5,488
Purchased power		467			187		742			601
Operation and maintenance		727			842		1,820			1,983
Depreciation and amortization		267			216		693			545
Property and other taxes		66			41		190			125

Total operating expenses		2,423			2,346		6,242			8,742


Operating Income		152			1,024		1,113			2,541
Other Income and Expenses		33			17		102			55
Interest Expense		258			140		596			425
Minority Interest Expense		3			51		76			234

(Loss) Earnings Before Income Taxes		(76	)		850		543			1,937
Income Tax (Benefit) Expense		(43	)		320		163			705

(Loss) Income Before Cumulative Effect of Change in Accounting Principle		(33	)		530		380			1,232
Cumulative Effect of Change in Accounting Principle, net of tax		—			—		—			(69	)

Net (Loss) Income	$	(33	)	$	530	$	380		$	1,163

See Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEETS

(In millions)

	September 30, 2002 (unaudited)		December 31, 2001
ASSETS
Current Assets
Cash and cash equivalents	$	368	$	263
Receivables		5,237		5,098
Inventory		683		503
Unrealized gains on mark-to-market and hedging transactions		3,057		2,275
Other		534		411

Total current assets		9,879		8,550


Investments and Other Assets
Investments in affiliates		2,204		1,480
Goodwill, net of accumulated amortization		3,941		1,729
Notes receivable		609		576
Unrealized gains on mark-to-market and hedging transactions		4,032		2,824
Other		1,904		1,919

Total investments and other assets		12,690		8,528


Property, Plant and Equipment
Cost		29,395		21,147
Less accumulated depreciation and amortization		3,820		3,120

Net property, plant and equipment		25,575		18,027


Regulatory Assets and Deferred Debits		878		185

Total Assets	$	49,022	$	35,290

See Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCED SHEETS

(In millions, except share amounts)

	September 30, 2002 (unaudited)			December 31, 2001
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	4,454		$	4,111
Notes payable and commercial paper		1,936			1,466
Taxes accrued		421			114
Interest accrued		251			191
Current maturities of long-term debt		909			254
Unrealized losses on mark-to-market and hedging transactions		2,562			1,523
Other		1,408			1,789

Total current liabilities		11,941			9,448


Long-term Debt		15,295			9,124


Deferred Credits and Other Liabilities
Deferred income taxes		2,544			2,215
Unrealized losses on mark-to-market and hedging transactions		3,370			1,957
Other		1,968			589

Total deferred credits and other liabilities		7,882			4,761


Commitments and Contingencies

Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation		825			824


Minority Interests in Financing Subsidiary		—			1,025


Minority Interests		1,905			1,221


Common Stockholder's Equity
Common stock, no par, 3,000 shares authorized, 1,010 shares outstanding		—			—
Paid-in capital		6,578			4,184
Retained Earnings		4,864			4,521
Accumulated other comprehensive (loss) income		(268	)		182

Total common stockholder's equity		11,174			8,887


Total Liabilities and Stockholder's Equity	$	49,022		$	35,290

See Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

	Nine Months Ended September 30,
	2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	380		$	1,163
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		693			545
Cumulative effect of change in accounting principle		—			69
Impairments of property, project sites and equipment		273			—
Deferred income taxes		7			310
(Increase) decrease in
Net unrealized mark-to-market and hedging transactions		396			(302	)
Receivables		1,415			(386	)
Inventory		(18	)		(39	)
Other current assets		(150	)		465
Increase (decrease) in
Accounts payable		(165	)		141
Taxes accrued		232			206
Other current liabilities		(324	)		227
Other, assets		265			300
Other, liabilities		(332	)		(133	)

Net cash provided by operating activities		2,672			2,566

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(2,859	)		(3,302	)
Investment expenditures		(636	)		(1,014	)
Acquisition of Westcoast Energy Inc., net of cash acquired		(1,690	)		—
Proceeds from the sale of subsidiaries		69			—
Notes receivable		177			121
Other		(127	)		182

Net cash used in investing activities		(5,066	)		(4,013	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		2,211			2,025
Payments for the redemption of long-term debt		(748	)		(505	)
Net change in notes payable and commercial paper		92			(703	)
Contributions from minortiy interests		1,931			12
Distributions to minority interests		(1,692	)		(70	)
Capital contributions from parent		650			650
Other		55			48

Net cash provided by financing activities		2,499			1,457

Net increase in cash and cash equivalents		105			10
Cash and cash equivalents at beginning of period		263			587

Cash and cash equivalents at end of period	$	368		$	597

Supplemental Disclosures
Cash paid for interest	$	531		$	450
Cash paid for income taxes	$	100		$	194
Acquisition of Westcoast Energy Inc.
Fair value of assets acquired	$	9,503
Liabilities assumed, including debt and minority interests		8,308
Capital contribution from parent from issuance of Duke Energy common stock		1,702
Non-cash Financing Activities
Reclassification of preferred member interest to debt	$	1,025

See Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Net (Loss) Income	($	33	)	$	530		$	380		$	1,163

Other comprehensive income (loss), net of tax
Cumulative effect of change in accounting principle		—			—			—			(908	)
Foreign currency translation adjustments		(230	)		(125	)		(356	)		(309	)
Net unrealized (losses) gains on cash flow hedges		(236	)		(20	)		(34	)		1,122
Reclassification into earnings		27			(285	)		(60	)		195

Total other comprehensive (loss) income		(439	)		(430	)		(450	)		100


Total Comprehensive (Loss) Income	($	472	)	$	100		($	70	)	$	1,263

See Notes to Consolidated Financial Statements.

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 six business segments.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the east coast and southern portion of the U.S. and in Canada. Natural Gas Transmission also provides distribution service to retail customers in Ontario and British Columbia and gas gathering and processing services to customers in British Columbia. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. The Company acquired Westcoast Energy Inc. (Westcoast) on March 14, 2002 (see Note 3). Duke Energy Gas Transmission’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commission (FERC), the Texas Railroad Commission’s, and the New York State Public Service Commission’s rules and regulations while natural gas gathering, processing, transmission, distribution and storage operations in Canada are subject to the rules and regulations of the National Energy Board, the Ontario Energy Board and the British Columbia Utilities Commission.

Field Services gathers, processes, transports, markets and stores natural gas and produces, transports, markets and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC, which is approximately 30% owned by ConocoPhillips. Field Services operates gathering systems in western Canada and 11 contiguous states in the U.S. Those systems serve major natural gas-producing regions in the Rocky Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, and onshore and offshore Gulf Coast areas.

Duke Energy North America (DENA) develops, operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil Corporation.

International Energy develops, operates and manages natural gas transportation and power generation facilities and engages in energy trading and marketing of natural gas and electric power outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC and its activities target the Latin American, Asia-Pacific and European regions.

Other Energy Services is composed of diverse energy businesses, operating primarily through Duke/Fluor Daniel (D/FD) and Energy Delivery Services (EDS). D/FD provides comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. It is a 50/50 partnership between the Company and Fluor Enterprises, Inc., a wholly owned subsidiary of Fluor Corporation. EDS is an engineering, construction, maintenance and technical services firm specializing in electric transmission and distribution lines and substation projects. It was formed in the second quarter of 2002 from the transmission and distribution services component of Duke Engineering & Services, Inc. (DE&S). This component was excluded from the sale of DE&S on April 30, 2002. Other Energy Services also retained other portions of DE&S that were not part of the sale and the portion of DukeSolutions, Inc. (DukeSolutions) that was not sold on May 1, 2002. DE&S and DukeSolutions were included in Other Energy Services through the date of their sale. See Note 3 for additional information on the sale of DE&S and DukeSolutions.

Duke Ventures is composed of other diverse businesses, operating primarily through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet) and Duke Capital Partners, LLC (DCP). Crescent develops high-quality commercial, residential and multi-family real estate projects and manages

land holdings primarily in the southeastern and southwestern U.S. DukeNet develops and manages fiber optic communications systems for wireless, local and long distance communications companies and selected educational, governmental, financial and health care entities. DCP, a wholly owned merchant banking company, provides debt and equity capital and financial advisory services primarily to the energy industry.

2. Summary of Significant Accounting Policies

Consolidation. The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the interim Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption and the timing of maintenance on electric generating units, among other factors.

Accounting for Hedges and Trading Activities. All derivatives not qualifying for the normal purchases and sales exemption under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. On the date that swaps, futures, forwards option contracts or other derivatives are entered into, the Company designates the derivative as either held for trading (trading instrument); as a hedge of a forecasted transaction or future cash flows (cash flow hedge); as a hedge of a recognized asset, liability or firm commitment (fair value hedge); or as a normal purchase or sale contract.

For hedge contracts, the Company formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. In accordance with SFAS No. 133, a gain on the time value of options of $1 million for the three months ended and zero for the nine months ended September 30, 2002, was excluded in the assessment and measurement of hedge effectiveness.

When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. As of September 30, 2002, 73% of the trading contracts’ fair value was determined using market prices and other external sources and 27% was determined using pricing models.

Values are adjusted to reflect the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is possible that such estimates may change in the near term.

Trading. Prior to settlement of any energy contract held for trading purposes, a favorable or unfavorable price movement is reported as Trading and Marketing Net Margin in the Consolidated Statements of Income. An offsetting amount is recorded on the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. When a contract to sell or buy is physically settled, the fair value entries are reversed and the gross amounts invoiced to the customer or due to the counterparty are included as Trading and Marketing Net Margin in the Consolidated Statements of Income. For financial settlement, the effect on the Consolidated Statements of Income is the same as physical transactions. For all contracts, the unrealized gain or loss on the Consolidated Balance Sheets is reversed and classified as a receivable or payable account until collected. See the “New Accounting Standards” section below for a discussion of the implications of the Financial Accounting Standard Board’s (FASB) Emerging Issues Task Force (EITF) Issue 02-03 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” on the accounting for trading activities prospectively.

Cash Flow Hedges. Changes in the fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive Income as Other Comprehensive Income (OCI) until earnings are affected by the hedged item. Settlement amounts and ineffective portions of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Income in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until the underlying contract is reflected in earnings, unless it is no longer probable that the hedged transaction will occur. Gains and losses that were accumulated in OCI will be immediately recognized in current-period earnings in those instances.

Fair Value Hedges. The Company enters into interest rate swaps to convert some of its fixed-rate long-term debt to floating-rate long-term debt and designates such interest rate swaps as fair value hedges. The Company also enters into electricity derivative instruments such as swaps, futures and forwards to manage the fair value risk associated with some of its unrecognized firm commitments to sell generated power due to changes in the market price of power. Upon designation of such derivatives as fair value hedges, prospective changes in the fair value of the derivative and the hedged item are recognized in current earnings. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

New Accounting Standards. The Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. The Company did not recognize any material impairment due to the implementation of SFAS No. 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon reassessment. No adjustments to intangibles were identified by the Company at transition.

The following table shows what net income would have been if amortization (including any related tax effects) related to goodwill that is no longer being amortized had been excluded from prior periods.

Goodwill – Adoption of SFAS No. 142 (in millions)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001

Net (Loss) Income
Reported net (loss) income	$	(33	)	$	530	$	380	$	1,163
Add back: Goodwill amortization, net of tax		—			18		—		53

Adjusted net (loss) income	$	(33	)	$	548	$	380	$	1,216

The changes in the carrying amount of goodwill for the nine months ended September 30, 2002 and 2001 are as follows:

Goodwill (in millions)

	Balance December 31, 2001		Acquired Goodwill		Other			Balance September 30, 2002
Natural Gas Transmission	$	481	$	2,274	$	—		$	2,755
Field Services		571		—		(90	)		481
Duke Energy North America		91		—		37			128
International Energy		427		12		(22	)		417
Other Energy Services		5		—		(5	)		—
Duke Ventures		—		—		6			6
Other Operations		154		—		—			154

Total consolidated	$	1,729	$	2,286	$	(74	)	$	3,941

	Balance December 31, 2000		Acquired Goodwill		Other			Balance September 30, 2001
Natural Gas Transmission	$	299	$	—	$	186		$	485
Field Services		507		19		(33	)		493
Duke Energy North America		12		—		56			68
International Energy		457		6		(57	)		406
Other Energy Services		46		—		(36	)		10
Other Operations		183		—		(21	)		162

Total consolidated	$	1,504	$	25	$	95		$	1,624

The Company adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale or as a discontinued operation. Adoption of the new standard had no material adverse effect on the Company’s consolidated results of operations or financial position.

In June 2002, the FASB’s EITF reached a partial consensus on Issue No. 02-03 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded in operating expenses, in accordance with prevailing industry practice. The amounts in the comparative interim Consolidated Statements of Income have been reclassified to conform to the 2002 presentation. The following table shows the impact of changing from gross to net presentation for energy trading activities on the Company’ revenues (offsetting adjustments were made to operating expenses resulting in no impact on net income).

Revenues – Implementation of Gross vs. Net Presentation in EITF Issue No. 02-03 (in millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001

Total revenues before adjustment	$	19,336	$	13,075	$	41,828	$	40,431
Adjustment		16,761		9,705		34,473		29,148

Revenues as reported	$	2,575	$	3,370	$	7,355	$	11,283

In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133 will be recorded at their historical cost and reported on an accrual basis resulting in the recognition of earnings or losses, at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 will be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 will be removed with a cumulative effect adjustment.

In connection with the decision to rescind Issue No. 98-10, the EITF also reached a consensus that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown net in the income statement as Trading and Marketing Net Margin (Loss). Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

The Company is currently assessing the provisions of Issue No. 02-03 and the rescission of Issue No. 98-10 but has not yet determined the impact on the results of operations or financial position.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated 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.

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 is increased due to the passage of time based on the time value of money until the obligation is settled.

The Company is required and plans to adopt the provisions of SFAS No. 143 as of January 1, 2003. To accomplish this, the Company must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Because of the effort needed to comply with the adoption of SFAS No. 143, the Company is currently assessing the new standard but has not yet determined the impact on its consolidated results of operations, cashflows or financial position.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF 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 will adopt 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 No. 94-3, a liability for an exit cost was recognized at 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.

Reclassifications. Certain prior period amounts have been reclassified to conform to the current presentation.

3. Business Acquisitions and Dispositions

Business Acquisitions. Using the purchase method for acquisitions, the Company consolidates assets and liabilities 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.

Acquisition of Westcoast Energy Inc. On March 14, 2002, the Company acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a wholly owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by the Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. Westcoast, headquartered in Vancouver, British Columbia, is a North American energy company with interests in natural gas gathering, processing, transmission, storage and distribution, as well as power generation and international energy businesses. In the transaction, a Company subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock), and approximately $1.7 billion in cash, net of cash acquired. Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities in November 2001 along with incremental commercial paper. The commercial paper is being repaid using the proceeds from a public offering of Duke Energy Common Stock. The Westcoast acquisition was accounted for using the purchase method of accounting, and goodwill totaling approximately $2.3 billion was recorded in the transaction.

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

Consolidated Pro Forma Results for the Company, including Westcoast (in millions)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001

Income Statement Data
Operating revenues	$	2,575		$	3,795	$	8,565	$	12,928
(Loss) Income before cumulative effect of change in accounting principle		(33	)		549		417		1,389
Cumulative effect of change in accounting principle, net of tax		—			—		—		(69	)
Net (Loss) Income	$	(33	)	$	549	$	417	$	1,320

Dispositions. DE&S. On April 30, 2002, the Company completed the sale of portions of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier) for $74 million. Some minor assets and two components of DE&S were not part of the sale and remain components of Other Energy Services. The Company established EDS in the second quarter of 2002 from the transmission and distribution services component of DE&S; EDS supplies transmission, distribution and substation services to customers. The Company retained its ownership interest in DCS, the prime contractor on the U.S. Department of Energy Mixed Oxide Fuel project. Operating results in 2002 include the pre-tax gain of $22 million on the sale of DE&S.

DukeSolutions. On May 1, 2002, the Company completed the sale of portions of DukeSolutions to Ameresco Inc. for $6 million. The portions that were not sold remain a component of Other Energy Services. Operating results in 2002 include the pre-tax loss on the sale of DukeSolutions of $25 million.

4. Derivative Instruments, Hedging Activities and Credit Risk

Commodity Cash Flow Hedges. Certain subsidiaries of the Company are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, processing and marketing activities. The Company closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of its future sales and generation revenues. The Company uses commodity instruments, such as swaps, futures, forwards and collared options, as cash flow hedges for natural gas, electricity and NGL transactions. The Company is hedging exposures to the price variability of these commodities for a maximum of 15 years.

For the nine months ended September 30, 2002 and 2001, the ineffective portion of commodity cash flow hedges was not material. As of September 30, 2002, $197 million of after-tax deferred net gains on derivative instruments were accumulated on the Consolidated Balance Sheet in a separate component of stockholders equity, OCI, 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 OCI will likely change prior to its reclassification into earnings.

Commodity Fair Value Hedges. Certain subsidiaries of the Company are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. The Company actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power and natural gas sales. The Company is hedging exposures to the market risk of such items for a maximum of 10 years. For the three and nine months ended September 30, 2002 and 2001, the ineffective portion of commodity fair value hedges was not material.

Trading Contracts. The Company provides energy supply, structured origination, trading and marketing, risk management and commercial optimization services to large energy customers, energy aggregators and other wholesale companies. These services require the Company to use natural gas, electricity, NGL and transportation derivatives and contracts that expose it to a variety of market risks. Duke Energy manages its trading exposure with policies that limit its market risk and require daily reporting of potential financial exposure to management. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose the Company to risk as a result of its issuance of variable-rate debt, fixed-to-floating interest rate swaps and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. The Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps, options, swaptions and lock agreements to manage and mitigate interest rate risk exposure. For the three and nine months ended September 30, 2002 and 2001, the Company’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position.

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. The Company also uses foreign currency

derivatives to manage its risk related to foreign currency fluctuations. For the three and nine months ended September 30, 2002 and 2001, the impact of the Company’s foreign currency derivative instruments was not material to its consolidated results of operations, cash flows or financial position.

Credit Risk. The Company’s principal customers for power and natural gas marketing services are industrial end-users, marketers and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. The Company has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. The Company frequently uses master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

Despite the current credit environment in the energy sector, management believes the credit risk management process described above is operating effectively. As of September 30, 2002, the Company held cash or letters of credit of $719 million to secure future performance, and had deposited with counterparties $292 million of such collateral to secure its obligations to provide future services. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. The Company may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, the Company’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted.

The change in market value of New York Mercantile Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of the Company’s counterparties.

As of September 30, 2002, the Company had a pre-tax bad debt provision of $90 million related to receivables for energy sales in California. Following the bankruptcy of Enron Corp., the Company terminated substantially all contracts with Enron Corp. and its affiliated companies (collectively, Enron). As a result, in 2001 the Company recorded, as a charge, a non-collateralized accounting exposure of $19 million. The $19 million non-collateralized accounting exposure was composed of charges of $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment’s earnings in 2001.

The Company’s determination of its bankruptcy claims against Enron is still under review, and its claims made in the bankruptcy case exceeded $19 million. Bankruptcy claims that exceed this amount primarily relate to termination and settlement rights under contracts and transactions with Enron that would have been recognized in future periods, and not in the historical periods covered by the financial statements to which the $19 million charge relates.

Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. The Company has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Duke Energy affiliate, Companhia de Geracao de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by the Company’s predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Company affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint

venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Company affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of the Company to cover its exposure.

5. 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. The following table shows how consolidated EBIT is calculated before deducting minority interests.

Reconciliation of Operating Income to EBIT (in millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001

Operating income	$	152	$	1,024	$	1,113	$	2,541
Plus: Other income and expenses		33		17		102		55

EBIT	$	185	$	1,041	$	1,215	$	2,596

EBIT is the primary performance measure used by management to evaluate segment performance. As an indicator of the Company’s operating performance or liquidity, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles. The Company’s EBIT may not be comparable to a similarly titled measure of another company.

In the accompanying tables, EBIT includes the profit on intersegment sales at prices representative of arms length transactions. Capital and investment expenditures are gross of cash received from acquisitions.

Business Segment Data (in millions)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures

Three Months Ended September 30, 2002
Natural Gas Transmission ^a	$	607		$	54		$	661		$	287		$	96	$	235
Field Services		884			197			1,081			23			74		66
Duke Energy North America		795			(298	)		497			(123	)		61		237
International Energy		222			(1	)		221			(25	)		27		133
Other Energy Services		(7	)		89			82			36			2		—
Duke Ventures		74			—			74			21			5		100
Other Operations ^b		—			(131	)		(131	)		(27	)		2		12
Eliminations and minority interests		—			90			90			(7	)		—		—

Total consolidated	$	2,575		$	—		$	2,575		$	185		$	267	$	783


Three Months Ended September 30, 2001
Natural Gas Transmission	$	238		$	33		$	271		$	143		$	35	$	238
Field Services		1,105			341			1,446			75			81		148
Duke Energy North America		1,485			(300	)		1,185			657			28		1,104
International Energy		182			5			187			74			24		106
Other Energy Services		102			41			143			(22	)		34		2
Duke Ventures		258			—			258			51			6		192
Other Operations ^b		—			(4	)		(4	)		26			8		25
Eliminations and minority interests		—			(116	)		(116	)		37			—		—

Total consolidated	$	3,370		$	—		$	3,370		$	1,041		$	216	$	1,815

^a Includes effects of the Westcoast acquisition on March 14, 2002. (See Note 3).

^b Other operations primarily includes certain unallocated corporate costs.

Business Segment Data (in millions)

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures

Nine Months Ended September 30, 2002
Natural Gas Transmission ^a	$	1,699	$	124		$	1,823		$	867		$	240	$	2,508
Field Services		2,654		681			3,335			99			219		250
Duke Energy North America		1,850		(755	)		1,095			47			129		1,758
International Energy		757		2			759			109			79		350
Other Energy Services		203		130			333			108			5		1
Duke Ventures		192		—			192			55			14		383
Other Operations ^b		—		(76	)		(76	)		(119	)		7		12
Eliminations and minority interests		—		(106	)		(106	)		49			—		—

Total consolidated	$	7,355	$	—		$	7,355		$	1,215		$	693	$	5,262


Nine Months Ended September 30, 2001
Natural Gas Transmission	$	712	$	105		$	817		$	460		$	106	$	524
Field Services		5,229		1,158			6,387			282			219		455
Duke Energy North America		4,079		(1,263	)		2,816			1,335			68		2,430
International Energy		553		9			562			218			72		264
Other Energy Services		317		76			393			(9	)		41		10
Duke Ventures		393		—			393			94			15		555
Other Operations ^b		—		118			118			24			24		84
Eliminations and minority interests		—		(203	)		(203	)		192			—		—

Total consolidated	$	11,283	$	—		$	11,283		$	2,596		$	545	$	4,322

^a Includes effects of the Westcoast acquisition on March 14, 2002. (See Note 3).

^b Other operations primarily includes certain unallocated corporate costs.

Segment assets in the accompanying 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, 2002		December 31, 2001

Natural Gas Transmission	$	15,520	$	5,027
Field Services		6,930		7,277
Duke Energy North America		18,282		14,005
International Energy		5,426		5,115
Other Energy Services		165		145
Duke Ventures		2,188		1,926
Other Operations, net of eliminations		511		1,795

Total consolidated	$	49,022	$	35,290

6. Debt

In February 2002, the Company issued $500 million of 6.25% senior unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due in 2032. In addition, the Company, through a private placement transaction, issued $500 million of floating rate (based on the one-month LIBOR plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these issuances were used for general corporate purposes.

In March 2002, a wholly owned subsidiary of the Company, Duke Australia Pipeline Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with various banks to fund its pipeline and power businesses in Australia. The facility is split between a Company-guaranteed tranche and a non-recourse project finance tranche that is secured by liens over existing Australian pipeline assets. Proceeds from the project finance tranche were used to repay inter-company loans.

In April 2002, the Company, through a private placement transaction, issued $100 million of floating rate (based on the one-month LIBOR plus 0.85%) senior unsecured bonds due in 2004. The proceeds from this issuance were used to repay commercial paper.

In July 2002, Texas Eastern Transmission, LP, a wholly owned subsidiary of the Company, issued $300 million of 5.25% senior unsecured bonds due in 2007 and $450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these issuances were used for general corporate purposes, including the repayment of debt which matured in July 2002, and for pipeline expansion and maintenance projects.

In 2000, Catawba River Associates LLC (Catawba), a consolidated entity of the Company, issued $1,025 million of preferred member interests to a third-party investor. The proceeds from the non-controlling investor were reflected on the Consolidated Balance Sheets as Minority Interest in Financing Subsidiary and were subsequently advanced to Duke Energy Power Generation (DEPG), a wholly owned subsidiary of the Company. In September 2002, Catawba distributed the receivable from DEPG to the preferred member, which simultaneously withdrew its interest. As a result, the $1,025 million that DEPG previously owed to Catawba became an obligation to the third-party investor and therefore was reclassified on the September 30, 2002 Consolidated Balance Sheet to Long-term Debt. In October 2002, the Company purchased the equity interests in the third party investor and effectively reduced the debt to $994 million. Additionally, the Company financially guaranteed the $994 million in return for certain modifications to the terms of the credit agreement.

Under its commercial paper and extendible commercial notes (ECNs) programs, the Company had the ability, subject to market conditions, to borrow up to $5,231 million as of September 30, 2002 compared with $3,608 million as of December 31, 2001. These programs do not have termination dates, but their usefulness is impacted by the existence of liquidity back stop bank credit facilities, as described below. The following table summarizes the Company’s commercial paper and ECN capacity as of September 30, 2002.

(in millions)	Duke Capital Corporation			Duke Energy Field Services		Duke Energy International		Westcoast		Total

Commercial Paper	$	2,550	^a	$	650	$	271	$	760	$	4,231
ECNs^b		1,000			—		—		—		1,000

Total	$	3,550		$	650	$	271	$	760	$	5,231

^aAmount was reduced to $1,550 commensurate with the closing of Duke Energy’s public offering of common stock in October 2002.

^b Although the Company routinely market ECNs, the demand for ECNs is minimal in the current markets.

The total borrowing capacity of the Company’s bank credit facilities, which primarily supports the issuance of commercial paper, was $5,599 million as of September 30, 2002 compared with $3,406 million as of December 31, 2001. The issuance of commercial paper, ECNs and letters of credit, along with borrowings, reduces the amount available under these credit facilities. As of September 30, 2002, $2,392 million of commercial paper and ECNs, and $229 million of letters of credit and borrowings were outstanding under the bank credit facilities. The credit facilities expire from December 2002 to 2005 and are not subject to minimum cash requirements. In addition, commensurate with the closing of Duke Energy’s public offering of common stock in October 2002, the borrowing capacity of the Company’s bank credit facilities was reduced by $900 million to $4,699 million. Also, in October 2002, the Company secured an option to borrow up to $500 million in February 2003 for a period ending no longer than November 2003.

As of September 30, 2002, the Company and its subsidiaries had effective Securities and Exchange Commission (SEC) shelf registrations for up to $1,000 million in gross proceeds from debt and other securities. As a result of the Westcoast acquisition, the Company has access to $602 million of unused capacity under a shelf registration in the Canadian market.

The Company’s debt agreements contain various financial and other covenants. Failure to meet these covenants beyond applicable grace periods could result in acceleration of due dates of the borrowings and/or termination of the agreements. As of September 30, 2002, the Company is in compliance with these covenants.

7. Commitments and Contingencies

Environmental. PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In March 1999, the Company sold Panhandle Eastern Pipe Line Company (PEPL) and Trunkline Gas Company (Trunkline) to CMS Energy Corporation (CMS). Under the terms of the sales agreement with CMS, the Company is obligated to complete the clean up of previously identified contamination resulting from the past use of PCB-containing lubricants and other discontinued practices at certain sites on the PEPL and Trunkline systems. In the third quarter of 2002, the Company completed the cleanup of previously contaminated sites on the PEPL and Trunkline systems and received a No Further Action determination from the state agency overseeing the cleanup, with the exception of one site which will require continued monitoring.

Notice of Proposed Rulemaking (NOPR). NOPR on Standards of Conduct. In September 2001, the FERC issued a NOPR announcing that it is considering new regulations regarding standards of conduct that would apply uniformly to natural gas pipelines that are currently subject to different gas standards. The proposed standards would change how companies and their affiliates interact and share information by broadening the definition of “affiliate” covered by the standards of conduct. Various entities filed comments on the NOPR with the FERC, including the Company’s parent company, Duke Energy, which filed comments in December 2001. In April 2002, the FERC Staff issued an analysis of the comments received from these entities. In several areas, the staff’s analysis reflects important changes to the NOPR. However, with regard to corporate governance, the staff’s analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions). A public conference was held in May 2002 to discuss the proposed revisions to the gas standards of conduct. Duke Energy filed supplemental comments with respect to the FERC Staff’s analysis in June 2002.

NOPR on Standard Market Design (SMD). On July 31, 2002, the FERC approved a NOPR entitled Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (Standard Market Design or SMD). The FERC has proposed to modify the open access transmission tariff and implement an SMD that would apply to Regional Transmission Organizations (RTOs) and also to individual utilities that have not yet joined an RTO. The FERC proposes to require each transmission owner to give an Independent Transmission Provider (ITP) operational control over the transmission owner’s facilities. These ITPs will file SMD Tariffs for transmission and ancillary services, administer day-ahead and real-time markets, monitor and mitigate market power, perform long-term resource adequacy, and participate in transmission planning and expansion on a regional basis.

Comments on certain aspects of the NOPR are due on November 15, 2002. The FERC has delayed until January 10, 2003, comments on transmission planning and pricing, states role, resource adequacy and congestion revenue rights. In the interim, the FERC will conduct numerous technical conferences to hear public comment on these issues. The NOPR contemplates implementation of SMD by 2004, although there are indications that the FERC expects the implementation timetable to be delayed. No date for the final rule has been set. The Company has completed a detailed review of the NOPR and expects to file initial comments by November 15, 2002.

NOPR on Asset Retirement Obligations. On October 30, 2002, the FERC issued a NOPR which seeks to establish a more transparent, complete and consistent reporting of liabilities associated with the retirement of long-lived assets. Among other things, the FERC proposes adding new balance sheet and income statement accounts to reflect the value of such liabilities, similar to the provisions in SFAS No. 143, “Accounting for Asset Retirement Obligations.” (See Note 2.) The changes are proposed to take effect on January 1, 2003 and apply to public utilities, natural gas firms and oil pipeline companies. The Company has initiated a detailed review of the NOPR. The Company is currently assessing the NOPR but has not yet determined the impact on its consolidated results of operations, cash flows or financial position.

Litigation and Contingencies. California Matters. Duke Energy, some of the Company’s 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 have been consolidated before a single judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master Amended Complaint in March 2002, which adds additional defendants. The claims against the 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 plaintiffs’ original and amended complaints.

The other nine of these 15 suits were filed in mid-2002, eight by plaintiffs in California and one by a plaintiff in the State of Washington. Eight of these suits are being considered for consolidation with the six previously filed lawsuits; one recently was filed but has not yet been served on Duke Energy. Various motions are pending before the courts, including motions concerning the jurisdiction of the courts and motions to dismiss claims of the parties.

On November 8, 2002, Duke Energy was served with a subpoena from a federal grand jury in San Francisco, California. In general, the subpoena asks for information relating to possible manipulation of the electricity markets in California, including, among other things, data pertaining to possible agreements among electricity energy producers and traders; price reporting data; scheduling and bid information data; plant capacity and outage data; sales, revenue, profits, production and costs data; and the like. 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.

The Company and its subsidiaries are involved in other legal and regulatory proceedings and investigations related to activities in California. These other activities were disclosed in the Company’s Form 10-K for the year ended December 31, 2001, and there have been no new material developments in relation to these matters.

Sacramento Municipal Utility District (SMUD) and City of Burbank, California FERC Complaints. The SMUD filed complaints on July 24, 2002 and the City of Burbank, California filed complaints on August 12, 2002, 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 when the western markets allegedly were dysfunctional and uncompetitive. The complainants request the FERC to set “just and reasonable” contract rates and a refund effective date.

DETM has filed its answers to the complaints asserting in each answer the same arguments and defenses set forth in response to the similar claims of Nevada Power (now settled and withdrawn, see the Company’s June 30, 2002 10-Q for details). On September 18, 2002 the FERC issued an order in the SMUD proceeding setting the matter for hearing and establishing a proposed effective refund date of September 22, 2002, but in the same order suspended the hearing for a time and appointed a settlement judge to convene prompt settlement proceedings among the parties. DETM has participated in the settlement proceedings. The FERC has not yet issued an order in the Burbank proceeding.

Colorado River Commission of Nevada (CRCN) /Pioneer Companies (Pioneer). The State of Nevada, through the CRCN, filed an “interpleader” complaint in federal court in Nevada on July 9, 2002, against Pioneer and 13 vendors, including DETM, who entered into power transactions with the CRCN between January 1998 and the filing date of the suit. The CRCN alleges that it purchased power on behalf of Pioneer but that Pioneer has disavowed its contractual liability to pay for certain of those power transactions. The CRCN asserts that DETM and the other vendors may have claims for the value of their contracts with the CRCN in excess of $100 million. The CRCN asks the court to assess the competing claims of the parties and distribute the assets which it seeks to deposit into the registry of the court (cash assets of approximately $35 million allegedly held for Pioneer’s behalf as well as the value of electric power delivered or to be delivered on Pioneer’s behalf) and issue other appropriate orders to resolve the claims while prohibiting the institution or prosecution of other proceedings affecting the claims at issue. DETM and certain other parties have filed motions to dismiss the complaint on various grounds. To date, payments to DETM pursuant to the pertinent contracts are current.

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. Two of the four North Carolina suits are based upon claims under the Employee Retirement Income and Security Act. The 13 lawsuits pending in New York have been consolidated into one action. Some of the lawsuits name as co-defendants Duke Energy executives and two investment banking firms. In addition, Duke Energy has received three shareholder’s 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 dates to the derivative demands have been extended to no earlier than first quarter 2003.

The class actions and the threatened shareholder derivative claims arise out of allegations that Duke Energy improperly engaged in trades involving simultaneous purchases and sales of power and gas at the same price (“round-trip” trading) which resulted in an alleged overstatement of revenues over a three-year period of approximately $1 billion. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys’ fees and costs for alleged violations of securities laws. In one of the lawsuits, the plaintiffs assert a common law fraud claim and seek, in addition to compensatory damages, disgorgement and punitive damages. These matters are in their earliest stages. Duke Energy continues to evaluate these claims and intends to vigorously defend the company and its named executives.

In 2002, Duke Energy received and responded to information requests from the FERC, a request for information from the SEC, a subpoena from the Commodity Futures Trading Commission, and a grand jury subpoena issued by the U.S. Attorney’s office in Houston. All information requests and subpoenas seek documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in mid-October that the SEC formalized its investigation regarding “round-trip” trading. Duke Energy is cooperating with the respective governmental agencies.

On October 25, 2002, FERC issued a data request to the “Largest North American Gas Marketers, As Measured by 2001 Physical Sales Volumes (Bcf/d),” including DETM. In general, the data request asks for information concerning natural gas price data that was submitted by the gas marketers to entities that publish natural gas price indices. On November 8, 2002, DETM provided an initial response to FERC in connection with the data request and indicated to FERC that DETM’s response would be supplemented as additional relevant information is gathered.

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 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.

8. Subsequent Events

In October 2002, the Company entered into a $240 million stock purchase agreement with National Fuel Gas Company pursuant to which National Fuel will acquire the Company’s Empire State Pipeline. The Empire State Pipeline, a natural gas pipeline that originates at the U.S./Canada border and extends into New York, was acquired by the Company as part of the Westcoast acquisition in March 2002 (See Note 3). The transaction, which is subject to a number of conditions including certain regulatory approvals, is expected to be finalized in early 2003.

For additional subsequent events, see Notes 6 and 7.

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 Duke Energy’s non-utility and other operations. The Company provides financing and credit enhancement services for its subsidiaries and conducts operations through its six business segments. See Note 1 to the Consolidated Financial Statements for descriptions of the Company’s business segments.

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

RESULTS OF OPERATIONS

For the three months ended September 30, 2002, net loss was $33 million, compared with net income of $530 million for the same period in 2001. The decrease was due primarily to an 83% decrease in earnings before interest and taxes (EBIT), as described below and a $103 million increase in interest expense due primarily to the debt assumed in the acquisition of Westcoast Energy Inc. (Westcoast) in March 2002. (See Note 3 to the Consolidated Financial Statements.) Slightly offsetting the comparative decrease in EBIT was a $48 million decrease in minority interest expense, as discussed in the following sections.

For the nine months ended September 30, 2002, net income was $380 million, compared to $1,163 million for 2001. The decrease was due primarily to a 54% decrease in EBIT, as described below, and a $126 million increase in interest expense. These changes were partially offset by the prior year’s one-time net-of-tax charge of $69 million, related to the cumulative effect of change in accounting principle for the January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Also offsetting the changes in EBIT and interest expense was a $158 million decrease in minority interest expense and a decrease in the effective tax rate, both of which are discussed in the following sections.

Operating income decreased $872 million to $152 million for the quarter and decreased $1,428 million to $1,113 million for the nine months ended September 30, 2002. EBIT decreased $871 million to $185 million for the quarter and decreased $1,426 million to $1,215 million for the nine months ended September 30, 2002. Operating income and EBIT are affected by the same fluctuations for the Company and each of its business segments. The following table shows the components of EBIT and reconciles EBIT to net income.

Reconciliation of Operating Income to Net (Loss) Income (in millions)

	Three Months Ended September 30,					Nine Months Ended September 30,

	2002			2001		2002		2001

Operating income	$	152		$	1,024	$	1,113	$	2,541
Other income and expenses		33			17		102		55

EBIT		185			1,041		1,215		2,596
Interest expense		258			140		596		425
Minority interest expense		3			51		76		234

(Loss) Earnings before income taxes		(76	)		850		543		1,937
Income tax (benefit) expense		(43	)		320		163		705

(Loss) Income before cumulative effect of change in accounting principle		(33	)		530		380		1,232
Cumulative effect of change in accounting principle, net of tax		—			—		—		(69	)

Net (loss) income	$	(33	)	$	530	$	380	$	1,163

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,

	2002			2001			2002			2001

Natural Gas Transmission	$	287		$	143		$	867		$	460
Field Services		23			75			99			282
Duke Energy North America		(123	)		657			47			1,335
International Energy		(25	)		74			109			218
Other Energy Services		36			(22	)		108			(9	)
Duke Ventures		21			51			55			94
Other Operations		(27	)		26			(119	)		24
EBIT attributable to minority interests		(7	)		37			49			192

Consolidated EBIT	$	185		$	1,041		$	1,215		$	2,596

Other Operations primarily includes certain unallocated corporate costs and elimination of intersegment profits. The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

Natural Gas Transmission

	Three Months Ended September 30,				Nine Months Ended September 30,

(in millions, except where noted)	2002		2001		2002		2001

Operating revenues	$	661	$	271	$	1,823	$	817
Operating expenses		375		131		954		363

Operating income		286		140		869		454
Other income, net of expenses		10		3		19		6
Minority interest expense		9		—		21		—

EBIT	$	287	$	143	$	867	$	460

Proportional throughput, TBtu^a		802		414		2,177		1,330

^aTrillion British thermal units

For the quarter ended September 30, 2002, EBIT for Natural Gas Transmission increased $144 million, and for the nine months, EBIT increased $407 million compared to the same periods in 2001. The increase for both periods primarily resulted from earnings from the natural gas transmission and distribution assets acquired as a part of the acquisition of Westcoast in March 2002. (See Note 3 to the Consolidated Financial Statements.) Earnings from Westcoast contributed $92 million for the quarter and $264 million for the nine months ended September 30, 2002.

For the quarter ended September 30, 2002, lower pipeline operating and maintenance costs contributed $14 million to the increase in EBIT. In addition, certain environmental issues were resolved resulting in the reversal of related reserves of $11 million for the quarter and $20 million for the nine months ended September 30, 2002. Also contributing to the increases in EBIT was an $18 million gain for the quarter and a $32 million gain for nine-month period ended September 30, 2002 on the sales of a portion of Natural Gas Transmission’s limited partnership interest in Northern Border Partners, LP.

Earnings associated with market expansion projects, including the Gulfstream Natural Gas System, a 581-mile pipeline system, 50% owned by the Company that went into service in May 2002, also contributed to earnings for the nine months ended September 30, 2002. These earnings included a $27 million

construction fee received during the second quarter of 2002 from an affiliate related to the successful completion of the Gulfstream Natural Gas System.

Field Services

	Three Months Ended September 30,					Nine Months Ended September 30,

(in millions, except where noted)	2002		2001			2002		2001

Operating revenues	$	1,081	$	1,446		$	3,335	$	6,387
Operating expenses		1,051		1,330			3,208		5,960

Operating income		30		116			127		427
Other income (loss), net of expenses		1		(5	)		1		(5	)
Minority interest expense		8		36			29		140

EBIT	$	23	$	75		$	99	$	282

Natural gas gathered and processed/transported, TBtu/d^a		8.4		8.8			8.4		8.5
Natural gas liquid (NGL) production, MBbl/d^b		395.1		412.8			392.0		396.9
Natural gas marketed, TBtu/d		1.6		1.6			1.6		1.6
Average natural gas price per MMBtu^c	$	3.18	$	2.88		$	2.97	$	4.88
Average NGL price per gallon^d	$	0.39	$	0.39		$	0.36	$	0.49

^aTrillion British thermal units per day

^bThousand barrels per day

^cMillion British thermal units

^dDoes not reflect results of commodity hedges

Field Services’ EBIT decreased $52 million for the quarter ended September 30, 2002 compared to the same period in 2001. The decrease was due primarily to higher operating, maintenance and administrative costs, an increase in its provision for gas imbalances with customers and suppliers, and other charges related to its ongoing internal review and reconciliations of balance sheet accounts.

EBIT for Field Services decreased $183 million for the nine months ended September 30, 2002 compared to 2001, due primarily to increases in operating and maintenance costs and decreases in commodity prices. The decrease in commodity prices was driven by decreases in average NGL prices of $0.13 per gallon for the nine months, partially offset by a decrease in the average natural gas prices of $1.91 per MMBtu for the nine months.

During the nine months ended September 2002, Field Services also recorded as part of its internal review of balance sheet accounts approximately $46 million of charges in the following five categories: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment account reconciliation; and other balance sheet accounts. Approximately $31 million of these charges are corrections of errors from prior years which are immaterial to the Company’s reported results. This review of balance sheet accounts is substantially complete.

Duke Energy North America

	Three Months Ended September 30,						Nine Months Ended September 30,

(in millions, except where noted)	2002			2001			2002			2001

Operating revenues	$	497		$	1,185		$	1,095		$	2,816
Operating expenses		648			527			1,066			1,446

Operating (loss) income		(151	)		658			29			1,370
Other (loss) income, net of expenses		—			(5	)		3			(1	)
Minority interest (benefit) expense		(28	)		(4	)		(15	)		34

EBIT	$	(123	)	$	657		$	47		$	1,335

Natural gas marketed, TBtu/d		16.3			12.4			17.5			12.4
Electricity marketed and traded, GWh		195,782			88,397			395,616			198,950
Proportional megawatt capacity in operation								14,211			6,799

For the quarter ended September 30, 2002, DENA’s EBIT decreased $780 million and for the nine months, it decreased $1,288 million, as compared to the same periods in 2001. Significant increases in the proportional megawatt capacity of generation assets in operation and increases in the marketing and trading of electricity and natural gas marketed volumes were more than offset by decreased trading and origination margins. DENA’s results reflect the negative impacts of a prolonged economic weakness, low commodity prices, continued low volatility levels (measures of the fluctuation in the prices of energy commodities or products), reduced spark spreads (the difference between the value of electricity and the value of the gas required to generate electricity), and decreased market liquidity. Last year’s results were primarily driven by relatively high spark spreads and higher volatility levels, especially in the western U.S. The quarter and nine months of 2001 also included net gains from the sale of interests in generating facilities as a result of DENA executing its portfolio management strategy.

The decrease in EBIT for both periods was also due to certain charges recorded in the third quarter of 2002. These charges related to current market conditions and strategic actions including provisions for 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 associated with the reduction in work force of $12 million. DENA estimates additional demobilization charges of approximately $25 million in the fourth quarter of 2002 related to the deferral of three plants in the western U.S.

Partially offsetting the decreases for both periods were lower variable compensation costs primarily related to the trading activities. Results for 2002 also include a decrease of $8 million for the quarter and an increase of $76 million for the nine months in the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques for all North American regions.

As a result of the Company’s findings in the course of its investigation related to the Securities and Exchange Commission’s (SEC) inquiry on electricity trades involving simultaneous purchases and sales of power at the same price (“round trip” trades), DENA recorded adjustments which reduced its EBIT by $17 million during the second quarter of 2002. An additional $2 million charge was recorded in other Duke Energy business segments related to these findings. The Company completed its analysis of such round trip

trades in the third quarter. As a result of this analysis, DENA recorded additional adjustments totaling $6 million which increased EBIT during the third quarter of 2002. (See Current Issues–Litigation and Contingencies, Trading Matters for additional information.)

For the current year quarter, increased losses at Duke Energy Trading and Marketing, LLC (DETM) resulted in an increased minority interest benefit of $25 million. When compared to the prior year, minority interest expense for the nine months decreased $49 million due to current year losses at DETM and changes in the ownership percentage of DENA’s waste-to-energy plants.

In June 2002, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods have been reclassified to reflect presentation on a net basis. (See Note 2 to the Consolidated Financial Statements.)

In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133 will be recorded at historical cost and reported on an accrual basis resulting in recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 will be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 will be removed with a cumulative effect adjustment.

In connection with the decision to rescind Issue No. 98-10, the EITF also reached a consensus that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should similarly be shown net in the income statement as Trading and Marketing Net Margin (Loss). Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

The Company is currently assessing the provisions of Issue No. 02-03 and the rescission of Issue No. 98-10 but has not yet determined the impact on the Company’s results of operations or financial position.

International Energy

	Three Months Ended September 30,					Nine Months Ended September 30,

(in millions, except where noted)	2002			2001		2002		2001

Operating revenues	$	221		$	187	$	759	$	562
Operating expenses		265			123		679		359

Operating (loss) income		(44	)		64		80		203
Other income, net of expenses		24			15		45		33
Minority interest expense		5			5		16		18

EBIT	$	(25	)	$	74	$	109	$	218

Sales, GWh^a		5,637			4,845		15,583		13,882
Natural gas marketed, TBtu/d		5.8			3.2		4.2		2.7
Electricity marketed and traded, GWh		20,871			3,234		62,743		6,625
Proportional megawatt capacity in operation							4,825		4,370
Proportional maximum pipeline capacity in Operation, MMcf/d^b							363		255

^aGWh sold by the operating assets to consumers, industrial users, etc.

^b Million cubic feet per day

International Energy’s EBIT decreased $99 million for the quarter and $109 million for the nine months ended September 30, 2002 compared to the same periods in 2001. The decreases were due primarily to $91 million in charges recorded in the third quarter 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. Both periods were also affected by decreased earnings from the European operations, which were affected by lower trading margins and liquidity.

Partially offsetting these decreases were increased earnings from the Latin American and Asia Pacific operations, which included additions to International Energy’s portfolio of assets from the Company’s acquisition of Westcoast. Earnings from Latin American operations also had comparative increases in EBIT due to the effects of the prior year’s reduced power consumption in Brazil (due to the government mandatory energy rationing caused by a period of severe drought). These comparative increases were partially offset by the negative impact of foreign currency devaluation on the earnings of the Latin American operations in 2002.

The increases in International Energy’s operating revenues and expenses for 2002 are due primarily to its increased trading and marketing activities in Europe.

Other Energy Services

	Three Months Ended September 30,					Nine Months Ended September 30,

(in millions)	2002		2001			2002		2001

Operating revenues	$	82	$	143		$	333	$	393
Operating expenses		46		164			225		406

Operating income (loss)		36		(21	)		108		(13	)
Other (loss) income, net of expenses		—		(1	)		—		4

EBIT	$	36	$	(22	)	$	108	$	(9	)

For the quarter ended September 30, 2002, EBIT for Other Energy Services increased $58 million and for the nine months, it increased $117 million, compared to the same periods in 2001. The increases for both periods were due primarily to increased earnings at Duke/Fluor Daniel (D/FD), as a result of D/FD completing a number of energy plants. Most of the plants were constructed for DENA and therefore the related intercompany profit has been eliminated within the Other Operations segment.

On April 30, 2002, the Company completed the sale of Duke Engineering & Services, Inc. to Framatome ANP, Inc. and, on May 1, 2002, the Company completed the sale of DukeSolutions, Inc. to Ameresco, Inc. (See Note 3 to the Consolidated Financial Statements). The combined result of these sales was a net loss of $3 million for the nine months. Prior year’s quarter and year-to-date results were negatively impacted by approximately $29 million of charges at Duke Engineering & Services, Inc. for goodwill impairment.

Duke Ventures

	Three Months Ended September 30,					Nine Months Ended September 30,

(in millions)	2002			2001		2002			2001

Operating revenues	$	74		$	258	$	192		$	393
Operating expenses		55			207		140			299

Operating income		19			51		52			94
Other income		1			—		1			—
Minority interest benefit		(1	)		—		(2	)		—

EBIT	$	21		$	51	$	55		$	94

EBIT for Duke Ventures decreased $30 million for the quarter and $39 million for the nine months ended September 30, 2002 compared to the same periods in 2001, primarily resulting from decreased earnings at Crescent Resources, LLC, due primarily to decreased commercial project sales and rents.

Other Operations

For the quarter ended September 30, 2002, Other Operations’ EBIT decreased $53 million and for the nine months, it decreased $143 million, compared to the same periods in 2001. The decreases are due primarily to increased intercompany profits between Duke Energy’s segments which are eliminated within the Other Operations segment. These intercompany profits are primarily a result of earnings at D/FD for energy plants it has under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission.

Other Impacts on Net Income

For the quarter ended September 30, 2002, interest expense increased $118 million and for the nine months ended September 30, 2002, interest expense increased $171 million compared to the same periods in 2001. The increases are due primarily to higher debt balances resulting from debt assumed in, and issued with respect to the acquisition of Westcoast.

Minority interest expense decreased $48 million for the quarter and $158 million for the nine months ended September 30, 2002 compared to the same periods in 2001. Minority interest expense includes expense related to regular distributions on preferred securities of the Company and its subsidiaries. This expense decreased $5 million for the quarter and $22 million for the nine months ended September 30, 2002 due primarily to lower distributions related to Catawba River Associates, LLC (Catawba). Catawba is a fully consolidated financing entity formed by the Company in September 2000 and is managed by a Company subsidiary. In September 2002, the holder of preferred member interest in Catawba exercised its right to require redemption of the preferred member interests. As a result, the Company made a non-cash transfer to reclassify the minority interest associated with Catawba from Minority Interest in Financing Subsidiary to Long-term Debt on the Consolidated Balance Sheets. (See Financing Cash Flows for additional information.)

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) decreased $43 million for the quarter and decreased $137 million for the nine month period. For the quarter, the change was driven by decreased income at DETM, DENA’s joint venture with Exxon Mobil Corporation, and decreased income from Duke Energy Field Services, LLC (DEFS), the Company’s joint venture with Conoco Phillips. For the nine months, the change was driven by decreased income from DEFS, changes in the ownership percentage of DENA’s waste-to-energy plants and decreased earnings at DETM.

A pretax loss and favorable foreign taxes due to the acquisition of regulated Westcoast entities resulted in an effective tax rate of approximately 57% for the quarter ended September 30, 2002, compared to approximately 38% for the same period in 2001. Lower pretax earnings, a state tax settlement finalized during the first quarter of 2002, and favorable foreign taxes due to the acquisition of regulated Westcoast entities, resulted in an effective tax rate of approximately 30% for the nine-month period ended September 30, 2002, compared to approximately 36% for the same period in 2001.

During the first quarter of 2001, the Company recorded a one time net-of-tax charge of $69 million related to the cumulative effect of change in accounting principle for the January 1, 2001 adoption of SFAS No. 133. This charge related to contracts that either did not meet the definition of a derivative under previous accounting guidance or do not qualify as hedges under new accounting requirements.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operations increased by $106 million to $2,672 million for the nine months ended September 30, 2002 from $2,566 million for the same period in 2001. The increase in 2002 operating cash flow compared to 2001 was primarily related to a decrease in cash earnings (see Results of Operations for further discussion) and changes in working capital for the comparable periods.

Investing Cash Flows

Net cash used in investing activities increased $1,053 million for the nine months ended September 30, 2002 when compared to the same period in 2001, primarily due to the acquisition of Westcoast for $1,690 million in cash, net of cash acquired (see Note 3 to the Consolidated Financial Statements). This was partially offset by a decrease in capital and investment expenditures of $821 million from 2001 to 2002. The decrease in capital and investment expenditures reflects significant decreases in current year expansion and development expenditures (especially related to DENA’s generating facilities) and higher acquisitions of minor businesses and assets in 2001.

Capital spending for 2002 is expected to be less than $4,800 million, excluding the acquisition of Westcoast. For 2003, the Company estimates capital spending to be approximately $2,100 million.

Financing Cash Flows

The Company’s cash requirements are expected to be funded largely by cash from operations, including the sale of assets. In addition, the Company expects to access the capital markets as needed. Ability to access the capital markets is dependent upon market opportunities presented. Management believes the Company has adequate financial flexibility and resources to meet its future needs.

In August 2002, Standard & Poor’s downgraded its long term ratings for the Company and its subsidiaries, with the exception of DEFS one ratings level, changing its outlook to Stable and leaving commercial paper ratings unchanged. Standard & Poor’s actions were based principally on a reassessment of the company’s consolidated creditworthiness and Standard & Poor’s perceived increase in risk of energy trading and merchant generation activities.

In September 2002, Moody’s Investors Service placed the long term ratings of the Company and its subsidiaries, with the exception of DEFS and the Maritimes & Northeast Pipeline companies, which are a component of Natural Gas Transmission, on review for potential downgrade. This action followed management’s recent decision to reduce the earnings outlook for the remainder of 2002 and 2003. A resolution to Moody’s action is expected during the fourth quarter of 2002.

In October 2002, Fitch Ratings downgraded its ratings for the Company one ratings level due primarily to the credit impacts from management’s recent decision to reduce the earnings outlook for the remainder of 2002 and 2003. Fitch Ratings concluded its ratings action leaving the Company and its subsidiaries, with the exception of DEFS, on Negative Outlook due to the on-going uncertainty surrounding the merchant power industry and investigations by the Federal Energy Regulatory Commission (FERC) and the SEC.

The Company’s credit ratings are dependent on, among other things, Duke Energy’s earnings for 2002 and the outlook for 2003. Management believes that Duke Energy’s earnings for 2003 could be below ongoing earnings for 2002 without an improvement in market conditions. If, as a result of market conditions or other factors affecting the Company’s business, Duke Energy is unable to achieve its earnings outlook or management lowers Duke Energy’s earnings outlook, the Company’s ratings could be adversely affected.

On March 14, 2002, the Company acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a wholly-owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by the Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. In addition to the debt assumed, Westcoast and Union Gas Limited have operating credit facilities of 600 million Canadian dollars each. Borrowings under each of these facilities are subject to and dependent upon the senior unsecured ratings of Westcoast (currently rated A (low) for Dominion Bond Rating Service (DBRS) and A for Standard & Poor’s) and Union Gas Limited (currently rated A for DBRS and A for Standard & Poor’s). For the Westcoast credit facility, no material adverse change can be declared if Westcoast maintains a rating of BBB (low) or greater at DBRS or a BBB– or greater at Standard & Poor’s. For Union Gas Limited’s facility, no material adverse change can be declared if Union Gas Limited maintains a rating of BBB or greater by either DBRS or Standard & Poor’s. For both facilities, any outstanding debt would not become due and payable as a result of a change in ratings.

Westcoast, headquartered in Vancouver, British Columbia, is a North American energy company with interests in natural gas gathering, processing, transmission, storage and distribution, as well as power generation and international energy businesses. In the transaction, a Company subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock), and approximately $1.7 billion in cash, net of cash acquired. Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in

stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities in November 2001 along with incremental commercial paper. The commercial paper is being repaid using the proceeds from a public offering of 54.5 million shares of common stock at $18.35. The shares from the public offering were issued in October 2002 and the proceeds were approximately $1.0 billion before underwriting commissions and other offering expenses. The Westcoast acquisition was accounted for using the purchase method of accounting, and goodwill totaling approximately $2.3 billion was recorded in the transaction.

(in millions)	Duke Capital Corporation			Duke Energy Field Services		Duke Energy International		Westcoast		Total

Commercial Paper	$	2,550	^a	$	650	$	271	$	760	$	4,231
ECNs		1,000			—		—		—		1,000

Total	$	3,550		$	650	$	271	$	760	$	5,231

^a Amount was reduced to $1,550 commensurate with the closing of Duke Energy’s public offering of common stock in October 2002.

^b Although the company routinely market ECNs, the demand for ECNs is minimal in the current markets.

As of September 30, 2002, the Company and its subsidiaries had effective SEC shelf registrations for up to $1,000 million in gross proceeds from debt and other securities. As a result of the Westcoast acquisition, the Company has access to $602 million of unused capacity under a shelf registration in the Canadian market.

CURRENT ISSUES

Environmental. PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In March 1999, the Company sold Panhandle Eastern Pipe Line Company (PEPL) and Trunkline Gas Company (Trunkline) to CMS Energy Corporation (CMS). Under the terms of the sales agreement with CMS, the Company is obligated to complete the clean up of previously identified contamination resulting from the past use of PCB-containing lubricants and other discontinued practices at certain sites on the PEPL and Trunkline systems. In the third quarter of 2002, the Company completed the cleanup of previously contaminated sites on the PEPL and Trunkline systems and received a No Further Action determination from the states agency overseeing the cleanup, with the exception of one site which will require continued monitoring.

of conduct. Various entities filed comments on the NOPR with the FERC, including the Company’s parent company, Duke Energy, which filed comments in December 2001. In April 2002, the FERC Staff issued an analysis of the comments received from these entities. In several areas, the staff’s analysis reflects important changes to the NOPR. However, with regard to corporate governance, the staff’s analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions). A public conference was held in May 2002 to discuss the proposed revisions to the gas standards of conduct. Duke Energy filed supplemental comments with respect to the FERC Staff’s analysis in June 2002.

Comments on certain aspects of the NOPR are due on November 15, 2002. The FERC has delayed until January 10, 2003, comments on transmission planning and pricing, states role, resource adequacy and congestion revenue rights. In the interim, The FERC will conduct numerous technical conferences to hear public comment on these issues. The NOPR contemplates implementation of SMD by 2004, although there are indications that the FERC expects the implementation timetable to be delayed. No date for the final rule has been set. The Company has completed a detailed review of the NOPR and expects to file initial comments by November 15, 2002.

NOPR on Asset Retirement Obligations. On October 30, 2002, the FERC issued a NOPR which seeks to establish a more transparent, complete and consistent reporting of liabilities associated with the retirement of long-lived assets. Among other things, the FERC proposes adding new balance sheet and income statement accounts to reflect the value of such liabilities, similar to the provisions in SFAS No. 143, “Accounting for Asset Retirement Obligations.” (See New Accounting Standards in this section.) The changes are proposed to take effect on January 1, 2003 and apply to public utilities, natural gas firms and oil pipeline companies. The Company has initiated a detailed review of the NOPR. The Company is currently assessing the NOPR but has not yet determined the impact on its consolidated results of operations, cash flows or financial position.

DETM has filed its answers to the complaints asserting in each answer the same arguments and defenses set forth in response to the similar claims of Nevada Power (now settled and withdrawn, see the Company’s June 30, 2002 10-Q for details). On September 18, 2002 the FERC issued an order in the SMUD proceeding setting the matter for hearing and establishing a proposed effective refund date of September 22, 2002, but in the same order suspended the hearing for a time and appointed a settlement judge to convene prompt settlement proceedings among the parties. DETM has participated in the settlement proceedings The FERC has not yet issued an order in the Burbank proceeding.

The class actions and the threatened shareholder derivative claims arise out of allegations that Duke Energy’s improperly engaged in the so-called “round-trip” trades which resulted in an alleged overstatement of revenues over a three-year period of approximately $1 billion. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys’ fees and costs for alleged violations of securities laws. In one of the lawsuits, the plaintiffs assert a common law fraud claim and seek, in addition to compensatory damages, disgorgement and punitive damages. These matters are in their earliest stages. Duke Energy continues to evaluate these claims and intends to vigorously defend the company and its named executives.

New Accounting Standards. In June 2002, the FASB’s EITF reached a partial consensus on Issue No. 02-03 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded in operating expenses, in accordance with prevailing industry practice. The amounts in the comparative interim Consolidated Statements of Income have been reclassified to conform to the 2002 presentation. The following table shows the impact of changing from gross to net presentation for energy trading activities on the Company’s revenues (offsetting adjustments were made to operating expenses resulting in no impact on net income).

Revenues – Implementation of Gross vs. Net Presentation in EITF Issue No. 02-03 (in millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001

Total revenues before adjustment	$	19,336	$	13,075	$	41,828	$	40,431
Adjustment		16,761		9,705		34,473		29,148

Revenues as reported	$	2,575	$	3,370	$	7,355	$	11,283

In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133 will be recorded at their historical cost and reported on an accrual basis resulting in recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 will be accounted for under the accrual accounting model. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 will be removed with a cumulative effect adjustment.

The Company is currently assessing the provisions of Issue No. 02-03 and the rescission of Issue No. 98-10 but has not yet determined the impact on the results of operations or financial position.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF 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 will adopt 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 No. 94-3, a liability for an exit cost was recognized at 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.

Subsequent Events.

In October 2002, the Company entered into a $240 million stock purchase agreement with National Fuel Gas Company pursuant to which National Fuel will acquire the Company’s Empire State Pipeline. The Empire State Pipeline, a natural gas pipeline that originates at the U.S./Canada border and extends into New York, was acquired by the Company as part of the Westcoast acquisition in March 2002. The transaction, which is subject to a number of conditions including certain regulatory approvals, is expected to be finalized in early 2003.

For additional subsequent events, see Liquidity and Capital Resources – Financing Cash Flows, and Current Issues – Litigation and Contingencies, and Regulatory Matters.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

RISK AND ACCOUNTING POLICIES

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

Mark-to-Market Accounting (MTM accounting). Under the MTM accounting method, an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in earnings during the current period. This accounting method has been used by other industries for many years, and in 1998 the EITF issued guidance that required MTM accounting for energy trading contracts. MTM accounting reports contracts at their “fair value,” (the value a willing third party would pay for the particular contract at the time a valuation is made). Recently issued accounting standards will be significantly changing MTM accounting, see Note 2 to the Consolidated Financial Statements for additional information.

When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using pricing models or pricing based on contracts with similar terms and risks. This is validated by an internal group independent of the Company’s trading area. Holders of thinly traded securities or investments (mutual funds, for example) use similar techniques to price such holdings. Commodity prices, correlation and volatility are the significant factors used in the computation of fair values. The Company validates its internally developed fair values by comparing locations/durations that are highly correlated, using market intelligence and mathematical extrapolation techniques. Changes in the Company’s pricing methodologies or the underlying assumptions could result in significantly different fair values, income recognition and realization in future periods.

Hedge Accounting. Hedging typically refers to the mechanism that the Company uses to mitigate the impact of volatility associated with price fluctuations. Hedge accounting treatment is used when the Company contracts to buy or sell a commodity such as natural gas or electricity at a fixed price for future delivery corresponding with anticipated physical sales or purchases of natural gas and power (cash flow hedge). In addition, hedge accounting treatment is used when the Company holds firm commitments or asset positions, and enters into transactions that “hedge” the risk that the price of natural gas or power may change between the contract’s inception and the physical delivery date of the commodity ultimately affecting the underlying value of the firm commitment or position (fair value hedge). The majority of the Company’s hedging transactions are used to protect the value of future cash flows related to its physical assets. To the extent the hedge is effective, the Company recognizes in earnings the value of the contract when the commodity is purchased or sold, or the hedged transaction occurs or settles.

Normal Purchases and Normal Sales, Special Exemption. A unique characteristic of the electric power industry is that electricity cannot be readily stored in significant quantities. As a result, some of the contracts to buy and sell electricity allow the buyer some flexibility in determining when to take electricity and in what quantity to match fluctuating demand. These contracts would normally meet the definition of a derivative requiring MTM or hedge accounting. However, because electricity cannot be readily stored in significant quantities and an entity engaged in selling electricity is obligated to maintain sufficient capacity to meet the electricity needs of its customer base, some electricity contracts with optionality features may qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and Derivative Implementation Group (DIG) Issue No. C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Therefore, contracts that the Company holds for the sale of power in future periods that meet the criteria in DIG Issue No. C15 have been designated as “normal purchases, normal sales” contracts, and are exempted from recognition in the Consolidated Financial Statements until power is delivered. The Company tracks these contracts separately in its hedge portfolio, but no value for these contracts is included in the Consolidated Financial Statements until power is actually delivered.

NORTH AMERICAN MERCHANT GENERATION

The Company’s wholesale energy portfolio in North America includes the merchant generation facilities and trading contracts held for power, natural gas, crude oil and petroleum products. The merchant generation facilities portion of the wholesale energy portfolio is anticipated to be realized in future periods as the generation facilities are dispatched. This future value includes hedge contracts and contracts designated as normal purchases and normal sales. Only the contracts designated and effective as qualifying hedges are reflected on the Company’s Consolidated Balance Sheets at fair value. Changes in the fair value of qualifying hedging contracts do not affect current-period earnings. Normal purchases and normal sales contracts are not subject to accounting recognition until contract performance occurs.

The remaining portion of the total estimated value of the wholesale energy portfolio is attributed to the current value of trading contracts. These contracts are subject to MTM accounting and changes in the contract fair value are recorded as part of current-period earnings. Recently issued accounting standards significantly change MTM accounting, see Note 2 to the Consolidated Financial Statements for additional information.

The following table shows when the expected discounted gross margin of the Company’s North American merchant generation facilities portion of the portfolio will be realized in future periods. The estimate is derived from the current forward market prices of fuels and power, less variable plant operating expenses through September 30, 2011 only and not for the life of the asset portfolio. It includes the value associated with hedge transactions and contracts designated as normal purchases and normal sales. It also includes the incremental margin attributed to managing and valuing the facilities as options. It does not include the value of any mark-to-market trading positions. Fixed plant operating costs, overhead, depreciation, taxes, reserves and future capital expenditures are also excluded, and the value presented is not intended to reflect fair market value of the portfolio.

North American Merchant Generation Portfolio Value as of September 30, 2002 (in millions)

Maturity in 2002	Maturity in 2003	Maturity in 2004	Maturity in 2005 and Thereafter	Total Portfolio Value

$163	$561	$528	$4,088	$5,340

The total portfolio value at June 30, 2002 was approximately $6 billion. The decrease from June 30, 2002 to September 30, 2002 primarily resulted from the curve updates resulting from changing market conditions and as a result of the deferral of three power plants under construction.

COMMODITY PRICE RISK

The Company, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options for trading purposes and for activity other than trading activity (primarily hedge strategies). (See Notes 2 and 4 to the Consolidated Financial Statements.)

Trading. The risk in the trading portfolio is measured and monitored on a daily basis using a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio (which includes all trading contracts not designated as hedge positions) on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days). The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for instruments held for trading purposes are shown in the following table.

Daily Earnings at Risk (in millions)

	Estimated Average One-Day Impact on EBIT for three months ended September 30, 2002^a	Estimated Average One-Day Impact on EBIT for three months ended September 30, 2001^a	High One-Day Impact on EBIT for three months ended September 30, 2002^a	Low One-Day Impact on EBIT for three months ended September 30, 2002^a

Calculated DER	$11	$12	$16	$7

^aAmount does not include the impact of Westcoast’s trading activity.

DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

The Company’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of the Company’s trading instruments during the three months ended September 30, 2002.

Changes in Fair Value of Trading Contracts (in millions)

Fair value of contracts outstanding at the beginning of the quarter	$	981
Contracts realized or otherwise settled during the period		(183	)
Fair value of contracts when entered into during the period		13
Net premiums received for new option contracts during the period		(45	)
Changes in fair value amounts attributable to changes in valuation techniques ^a		(3	)
Other changes in fair values		(236	)

Fair value of contracts outstanding at the end of the quarter	$	527

^aAmount represents change of the fair value of the mark-to-market portfolio as a result of applying improved valuation modeling techniques. During the quarter ended September 30, 2002, the Company refined its definition of a change in valuation technique to exclude changes in methodologies used to estimate market inputs which are not readily observable. Changes in such methodologies are included in other changes in fair values.

The unrealized net loss recognized in operating income was $148 million for the quarter and $152 million for the nine months ended September 30, 2002. The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values.

When available, the Company uses observable market prices for valuing its trading instruments. When quoted market prices are not available, management uses established guidelines for the valuation of these contracts. Management may use a variety of reasonable methods to assist in determining the valuation of a trading instrument, including analogy to reliable quotations of similar trading instruments, pricing models, matrix pricing and other formula-based pricing methods. These methodologies incorporate factors for which published market data may be available. All valuation methods employed by the Company are approved by an independent internal corporate risk management organization.

The following table shows the fair value of the Company’s trading portfolio as of September 30, 2002.

Fair Value of Trading Contracts as of September 30, 2002 (in millions)

Sources of Fair Value	Maturity in 2002		Maturity in 2003		Maturity in 2004			Maturity in 2005 and Thereafter		Total Fair Value
Prices supported by quoted market prices and other external sources	$	100	$	115	$	110		$	60	$	385
Prices based on models and other valuation methods		24		10		(25	)		133		142

Total	$	124	$	125	$	85		$	193	$	527

The “prices supported by quoted market prices and other external sources” category includes the Company’s New York Mercantile Exchange (NYMEX) futures positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes the Company’s forward positions and options in natural gas and power and natural gas basis swaps at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for natural gas and power forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas and power options extend 12 months into the future, on average. The Company values these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. It is important to understand that in certain instances structured transactions can be decomposed and modeled by the Company as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions.

The Company’s trading portfolio valuation adjustments for liquidity, credit and cost of service are reflected in the above amounts.

Hedging Strategies. The Company’s 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 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. Contract terms are up to 15 years. These contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by the Company to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in Other Comprehensive Income (OCI) for cash flow hedges and included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 2 and 4 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month.

The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, as mentioned previously, the gains and losses for these contracts are not recognized in earnings until settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement.

The fair value of the Company qualifying hedge positions at a point in time is not necessarily indicative of the value realized when such contracts settle.

Fair Value of Hedge Position Contracts as of September 30, 2002 (in millions) ^a

Maturity in 2002	Maturity in 2003	Maturity in 2004	Maturity in 2005 and Thereafter	Total Contract Value

$76	$148	$137	$269	$630

^aIncludes foreign currency and interest rate hedges that net to approximately a $19 million gain

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, the Company enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward agreements to sell power, bear the same counterparty credit risk as the hedge contracts described above. Under the same risk reduction guidelines used for other contracts, normal purchases and sales contracts are also subject to collateral requirements. Income recognition and realization related to these contracts coincide with the physical delivery of power.

CREDIT RISK

The Company’s principal customers for power and natural gas marketing services are industrial end-users, marketers and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. The Company has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. The Company frequently uses master collateral agreements to mitigate credit exposure. The collateral agreement provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

Despite the current credit environment in the energy sector, management believes that the credit risk management process described above is operating effectively. As of September 30, 2002, the Company held cash or letters of credit of $719 million to secure such future performance, and had deposited with counterparties $292 million of such collateral to secure its obligations to provide such future services. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. The Company may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, the Company’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted.

The change in market value of NYMEX-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of the Company’s counterparties.

Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. The Company has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Company affiliate, Companhia de Geracao de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by the Company’s predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Company affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Company affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of the Company to cover its exposure.

INTEREST RATE RISK

The Company is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt, fixed-to-floating interest rate swaps and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. The Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps, options, swaptions and lock agreements to manage and mitigate interest rate risk exposure. (See Notes 2, 4, and 6 to the Consolidated Financial Statements.)

EQUITY PRICE RISK

The Company participates in Duke Energy’s non-contributory defined benefit retirement and post retirement benefit plans. Duke Energy’s, and therefore the Company’s, costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by declines in the equity market since the third quarter of 2000. As a result, as of September 30, 2002, Duke Energy’s pension plan obligation exceeded the value of the plan assets and therefore Duke Energy was required to recognized a minimum pension liability as prescribed by SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 132 “Employers’ Disclosures about Pensions and Postretirement Benefits.” Pension cost and cash funding requirements for Duke Energy could increase in future years without a substantial recovery in the equity markets. In the event future cash funding for the plan is required, the Company would be required to fund its portion to Duke Energy on a pro rata basis.

FOREIGN CURRENCY RISK

The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. The Company also uses foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, the Company uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

Item 4. Controls and Procedures

The Company’s management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of the Company’s disclosure controls and procedures as defined in Exchange Act Rule 13a-14 during October and November 2002. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that 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 internal controls, or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.

In 2001, DEFS, along with its external auditors, identified certain deficiencies in the design and operation of its internal control procedures that were reportable control weaknesses. These control weaknesses related to balance sheet reconciliations, including supervisory review of such reconciliations, gas imbalances, joint venture accounting, employee benefit accruals and revenue related issues. In addition, there were identified weaknesses reported in the areas of risk management procedures, accounts receivable, revenue accrual and natural gas liquid accounting. Throughout 2002, DEFS implemented internal control enhancements in each of the areas described above. These enhancements included improved systems and processes, implementation of accounting policies related to gas imbalances and other enhancements related to joint venture accounting, risk management procedures, and revenue and natural gas liquids accounting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Duke Capital Corporation’s subsidiary, Duke Energy Field Services (DEFS) received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) in the spring of 2001 enabling DEFS to discharge certain wastewater streams from its Minden Gas Processing Plant until the LDEQ issued a new discharge permit. The Compliance Order authorized certain discharges, and otherwise addressed various historic and recent deviations from Clean Water Act regulatory requirements, including the lapse of the facility’s discharge permit. The LDEQ issued a new discharge permit in the spring of 2002 and DEFS completed operational improvements in the fall of 2002 that resulted in the cessation of remaining point source discharges. In August 2002, a penalty assessment was issued by the LDEQ in the amount of $155,383. DEFS paid the penalty and has notified the LDEQ that all items in the Compliance Order have been completed.

For additional information concerning litigation and other contingencies, see Note 7 to the Consolidated Financial Statements, “Commitments and Contingencies,” and Item 3, “Legal Proceedings,” and Note 12 to the Consolidated Financial Statements, “Commitments and Contingencies,” included in the Company’s Form 10-K for December 31, 2001, which are incorporated herein by reference.

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

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

(a) Exhibits

Exhibit Number
99.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2		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

A Current Report on Form 8-K filed on August 14, 2002 contained disclosures under Item 9, Regulation FD Disclosure.

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

November 14, 2002						/s/ ROBERT P. BRACE
						Robert P. Brace Vice President and Chief Financial Officer


November 14, 2002						/s/ KEITH G. BUTLER
						Keith G. Butler Controller

CERTIFICATIONS

I, Robert P. Brace certify that:

1. I have reviewed this quarterly report on Form 10-Q of Duke Capital Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002

/s/ ROBERT P. BRACE

Robert P. Brace

Vice President and Chief Financial Officer

CERTIFICATIONS

I, Richard B. Priory certify that:

1. I have reviewed this quarterly report on Form 10-Q of Duke Capital Corporation;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 14, 2002

/s/ RICHARD B. PRIORY

Richard B. Priory

Chairman of the Board and President