<PAGE>


--------------------------------------------------------------------------------
                                 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 March 31, 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
April 30,2002.......................1,010

<PAGE>

                            DUKE CAPITAL CORPORATION
                 FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2002
                                      INDEX
<TABLE>
<CAPTION>
Item                                                                                                   Page
----                                                                                                   ----
                                      PART I. FINANCIAL INFORMATION
<S>                                                                                                    <C>

1.  Financial Statements...............................................................................1
        Consolidated Statements of Income for the Three Months Ended
             March 31, 2002 and 2001...................................................................1
        Consolidated Statements of Cash Flows for the Three Months Ended
             March 31, 2002 and 2001...................................................................2
        Consolidated Balance Sheets as of March 31, 2002 and December 31, 2001.........................3
        Consolidated Statements of Comprehensive Income (Loss) for the Three Months
             Ended March 31, 2002 and 2001.............................................................5
        Notes to Consolidated Financial Statements.....................................................6
2.  Management's Discussion and Analysis of Results of Operations and Financial Condition.............15

                                        PART II. OTHER INFORMATION

1.  Legal Proceedings.................................................................................30
6.  Exhibits and Reports on Form 8-K..................................................................30
    Signatures........................................................................................31
</TABLE>

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

The Company's reports, filings and other public announcements may include
statements that reflect assumptions, projections, expectations, intentions or
beliefs about future events. These statements are intended as "forward-looking
statements" under the Private Securities Litigation Reform Act of 1995.
Generally, the words "may," "could," "project," "believe," "anticipate,"
"expect," "estimate," "plan," "forecast," "intend" and similar words identify
forward-looking statements, which generally are not historical in nature. All
such statements (other than statements of historical facts), including
statements regarding operating performance, financial position, business
strategy, budgets, projected costs, plans and objectives of management for
future operations and events or developments that we expect or anticipate will
occur in the future, are forward looking. Forward-looking statements are subject
to certain risks and uncertainties that could, and often do, cause actual
results to differ from the Company's historical experience and our present
expectations or projections. Accordingly, there can be no assurance that actual
results will not differ materially from those expressed or implied by the
forward-looking statements. Caution should be taken not to place undue reliance
on any such forward-looking statements.

Factors that could cause actual results to differ materially from the
expectations expressed or implied in such forward-looking statements include,
but are not limited to: state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on rate
structures and affect the speed and degree at which competition enters the
electric and natural gas industries; industrial, commercial and residential
growth in the service territories of the Company's subsidiaries; 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 the Company and its
subsidiaries are subject or other external factors over which the Company has
no control; the results of financing efforts, including the Company's ability
to obtain financing on favorable terms, which can be affected by the Company's
credit rating and general economic conditions; level of creditworthiness of
counterparties to transactions; growth opportunities for the Company's business
units; and the effect of accounting policies issued periodically by accounting
standard-setting bodies.

                                       i

<PAGE>

                         PART I. FINANCIAL INFORMATION
 Item 1. Financial Statements.

                       CONSOLIDATED STATEMENTS OF INCOME
                                  (Unaudited)
                                 (In millions)

<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                                                  March 31,
                                                                       -------------------------------
                                                                           2002               2001
                                                                       ------------       ------------
<S>                                                                     <C>                <C>
Operating Revenues
     Sales, trading and marketing of natural gas
        and petroleum products                                          $    4,526         $   10,538
     Trading and marketing of electricity                                    4,027              3,239
     Transportation and storage of natural gas                                 326                246
     Electric generation                                                       610                145
     Other                                                                     200                232
                                                                       ------------       ------------
          Total operating revenues                                           9,689             14,400
                                                                       ------------       ------------

Operating Expenses
     Natural gas and petroleum products purchased                            4,379             10,112
     Purchased power                                                         4,130              2,648
     Other operation and maintenance                                           569                544
     Depreciation and amortization                                             188                162
     Property and other taxes                                                   61                 45
                                                                       ------------       ------------
          Total operating expenses                                           9,327             13,511
                                                                       ------------       ------------

Operating Income                                                               362                889

Other Income and Expenses                                                       47                 10
Interest Expense                                                               131                145
Minority Interest Expense                                                       21                149
                                                                       ------------       ------------

Earnings Before Income Taxes                                                   257                605
Income Taxes                                                                    83                217
                                                                       ------------       ------------

Income Before Cumulative Effect of Change in Accounting Principle              174                388
Cumulative Effect of Change in Accounting Principle, net of tax                  -                (69)
                                                                       ------------       ------------

Net Income                                                              $      174         $      319
                                                                       ============       ============
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       1

<PAGE>

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                  (Unaudited)
                                 (In millions)

<TABLE>
<CAPTION>

                                                                              Three Months Ended
                                                                                   March 31,
                                                                       -------------------------------
                                                                           2002               2001
                                                                       ------------       ------------
<S>                                                                     <C>                <C>
CASH FLOWS FROM OPERATING ACTIVITIES
   Net income                                                           $      174         $      319
   Adjustments to reconcile net income to net cash provided by
      operating activities
           Depreciation and amortization                                       190                162
           Cumulative effect of change in accounting principle                 -                   69
           Deferred income taxes                                               (40)               237
           (Increase) decrease in
                Net unrealized mark-to-market and hedging transactions         233               (601)
                Receivables                                                  1,882               (487)
                Inventory                                                       90                120
                Other current assets                                          (201)              (479)
           Increase (decrease) in
                Accounts payable                                              (510)               785
                Taxes accrued                                                    9               (197)
                Interest accrued                                                (7)                 8
                Other current liabilities                                     (593)              (111)
           Other, assets                                                       145                 46
           Other, liabilities                                                 (186)               (92)
                                                                       ------------       ------------
                Net cash provided by (used in) operating activities          1,186               (221)
                                                                       ------------       ------------

CASH FLOWS FROM INVESTING ACTIVITIES
   Capital expenditures, net of cash acquired                               (1,023)              (548)
   Investment expenditures                                                    (319)              (300)
   Acquisition of Westcoast Energy, Inc., net of cash acquired              (1,690)               -
   Other                                                                        22                 99
                                                                       ------------       ------------
                Net cash used in investing activities                       (3,010)              (749)
                                                                       ------------       ------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Proceeds from the issuance of long-term debt                              1,352              1,339
   Payments for the redemption of long-term debt                              (406)               (63)
   Net change in notes payable and commercial paper                            612             (1,158)
   Distributions to minority interests                                         (84)               -
   Capital contributions from parent                                           250                650
   Other                                                                       (37)               (93)
                                                                       ------------       ------------
                Net cash provided by financing activities                    1,687                675
                                                                       ------------       ------------

Net decrease in cash and cash equivalents                                     (137)              (295)
Cash and cash equivalents at beginning of period                               263                587
                                                                       ------------       ------------
Cash and cash equivalents at end of period                              $      126         $      292
                                                                       ============       ============

Supplemental Disclosures
   Cash paid for interest, net of amount capitalized                    $       91         $      150
   Cash paid for income taxes                                           $       73         $      177

   Acquisition of Westcoast Energy, Inc.
      Fair value of assets acquired                                     $    9,487
      Liabilities assumed, including debt and minority interests             8,382
      Issuance of common stock                                               1,797
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       2

<PAGE>

                          CONSOLIDATED BALANCE SHEETS
                                 (In millions)

<TABLE>
<CAPTION>
                                                                         March 31,        December 31,
                                                                          2002                2001
                                                                       (unaudited)
                                                                       ------------       ------------
<S>                                                                     <C>                <C>
ASSETS
Current Assets
   Cash and cash equivalents                                            $      126         $      263
   Receivables                                                               4,800              5,098
   Inventory                                                                   575                503
   Unrealized gains on mark-to-market and hedging transactions               3,805              2,275
   Other                                                                       620                411
                                                                       ------------       ------------
      Total current assets                                                   9,926              8,550
                                                                       ------------       ------------

Investments and Other Assets
   Investments in affiliates                                                 2,076              1,480
   Goodwill, net of accumulated amortization                                 4,084              1,729
   Notes receivable                                                            628                576
   Unrealized gains on mark-to-market and hedging transactions               4,147              2,824
   Other                                                                     1,794              1,919
                                                                       ------------       ------------
      Total investments and other assets                                    12,729              8,528
                                                                       ------------       ------------

Property, Plant and Equipment
   Cost                                                                     28,345             21,147
   Less accumulated depreciation and amortization                            3,523              3,120
                                                                       ------------       ------------
      Net property, plant and equipment                                     24,822             18,027
                                                                       ------------       ------------
Regulatory Assets and Deferred Debits                                          890                185
                                                                       ------------       ------------

Total Assets                                                            $   48,367         $   35,290
                                                                       ============       ============
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       3

<PAGE>

                          CONSOLIDATED BALANCE SHEETS
                      (In millions, except share amounts)

<TABLE>
<CAPTION>
                                                                         March 31,        December 31,
                                                                           2002               2001
                                                                       (unaudited)
                                                                       ------------       ------------
<S>                                                                     <C>                <C>
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
   Accounts payable                                                     $    4,048         $    4,111
   Notes payable and commercial paper                                        2,440              1,466
   Taxes accrued                                                               174                114
   Interest accrued                                                            232                191
   Current maturities of long-term debt                                        446                254
   Unrealized losses on mark-to-market and hedging transactions              2,984              1,523
   Other                                                                     1,103              1,789
                                                                       ------------       ------------
       Total current liabilities                                            11,427              9,448
                                                                       ------------       ------------

Long-term Debt                                                              14,236              9,124
                                                                       ------------       ------------

Deferred Credits and Other Liabilities
   Deferred income taxes                                                     2,454              2,215
   Unrealized losses on mark-to-market and hedging transactions              3,311              1,957
   Other                                                                     2,197                589
                                                                       ------------       ------------
       Total deferred credits and other liabilities                          7,962              4,761
                                                                       ------------       ------------
Guaranteed Preferred Beneficial Interests in Subordinated
       Notes of Duke Capital Corporation                                       824                824
                                                                       ------------       ------------

Minority Interests in Financing Subsidiary                                   1,025              1,025
                                                                       ------------       ------------

Minority Interests                                                           1,641              1,221
                                                                       ------------       ------------

Common Stockholder's Equity
   Common stock, no par, 3,000 shares authorized,
       1,010 shares outstanding                                                 -                  -
   Paid-in capital                                                           6,231              4,184
   Retained Earnings                                                         4,700              4,521
   Accumulated other comprehensive income                                      321                182
                                                                       ------------       ------------
       Total common stockholder's equity                                    11,252              8,887
                                                                       ------------       ------------

Total Liabilities and Stockholder's Equity                              $   48,367         $   35,290
                                                                       ============       ============
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       4

<PAGE>

             CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
                                  (Unaudited)
                                 (In millions)

<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                                                 March 31,
                                                                       -------------------------------
                                                                            2002              2001
                                                                       ------------       ------------
<S>                                                                     <C>                <C>
Net Income                                                              $      174         $     319

Other comprehensive income, net of tax
   Cumulative effect of change in accounting principle                         -                (908)
   Foreign currency translation adjustment                                     (24)             (137)
   Net unrealized gains (losses) on cash flow hedges                           275              (358)
   Reclassification into earnings                                             (112)              175
                                                                       ------------       ------------
      Total other comprehensive income                                         139            (1,228)
                                                                       ------------       ------------

Total Comprehensive Income (Loss)                                       $      313         $    (909)
                                                                       ============        ===========
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       5

<PAGE>

                   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, storage and distribution of
natural gas for customers throughout the east coast and southern portion of the
U.S. and Canada. Natural Gas Transmission provides gas gathering, processing and
transportation services to customers located in British Columbia, Canada and in
the Pacific northwest region of the U.S. 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). Interstate
natural gas transmission and storage operations in the U.S. are subject to the
Federal Energy Regulatory Commission's (FERC)'s rules and regulations while
natural gas gathering, processing, transmission, distribution and storage
operations in Canada are subject to the National Energy Board, Ontario Energy
Board and British Columbia Utilities Commission rules and regulations.

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 Phillips Petroleum. 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.

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

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. 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 a combination of businesses that provide engineering,
consulting, construction and integrated energy solutions worldwide, primarily
through Duke Engineering & Services, Inc. (DE&S), Duke/Fluor Daniel (D/FD) and
DukeSolutions, Inc. (DukeSolutions). D/FD is a 50/50 partnership between the
Company and Fluor Enterprises, Inc., a wholly owned subsidiary of Fluor
Corporation. On April 30, 2002, the Company completed the sale of DE&S to
Framatome ANP, Inc. and, on May 1, 2002, the Company completed the sale of
DukeSolutions to Ameresco, Inc. (See Note 3).

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 provides
fiber optic networks for industrial, commercial and residential customers. DCP,
a wholly owned merchant banking company, provides debt and equity capital and
financial advisory services to the energy industry.

                                       6

<PAGE>

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 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.

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 or option contracts 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); as a normal purchase or sale contract; or leaves
the derivative undesignated and marks it to market.

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. A
loss on the time value of options of $2 million was excluded in the assessment
and measurement of hedge effectiveness for the three months ended March 31,
2002.

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.

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 reasonably 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 Natural Gas and Petroleum
Products Purchased, or Purchased Power 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 is physically settled, the fair value
entries are reversed and the gross amount invoiced to the customer is included
as Sales, Trading and Marketing of Natural Gas and Petroleum Products, or
Trading and Marketing of Electricity, in the Consolidated Statements of Income.
Similarly, when a contract to purchase is physically settled, the purchase price
is included as Natural Gas and Petroleum Products Purchased, or Purchased Power
in the Consolidated Statements of Income. If a contract is not financially
settled, the unrealized gain or loss on the Consolidated Balance Sheets is
reversed and reclassified to a receivable or payable account. For income
statement purposes, financial settlement has no revenue presentation effect on
the Consolidated Statements of Income.

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 (Loss) 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

                                       7

<PAGE>

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 earnings are affected by the hedged item, 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 in a manner consistent with the earnings effect of the hedged risk. 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 at 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
                                                              March 31,
                                                 -------------------------------
                                                      2002              2001
                                                 -------------------------------
Net Income
  Reported net income                                 $174              $319
  Add back:  Goodwill amortization, net of tax           -                12
                                                 -------------------------------
  Adjusted net income                                 $174              $331
--------------------------------------------------------------------------------

The changes in the carrying amount of goodwill for the three months ended March
31, 2002 and March 31, 2001 are as follows:

<TABLE>
<CAPTION>
==============================================================================================
Goodwill (in millions)
==============================================================================================
                                     Balance                                        Balance
                                   December 31,       Acquired                     March 31,
                                      2001            Goodwill        Other          2002
                                 -------------------------------------------------------------
<S>                                 <C>                <C>            <C>          <C>
Natural Gas Transmission            $  481             $2,459         $   -        $2,940
Field Services                         571                  -          (106)          465
North American Wholesale
   Energy                               91                  -             9           100
International Energy                   427                               (4)          423
Other Energy Services                    5                  -            (3)            2
Other Operations                       154                  -             -           154
                                 -------------------------------------------------------------
   Total consolidated               $1,729             $2,459         $(104)       $4,084
----------------------------------------------------------------------------------------------
</TABLE>

                                       8

<PAGE>

<TABLE>
==============================================================================================
Goodwill (in millions)
==============================================================================================
                                     Balance                                        Balance
                                  December 31,       Acquired                      March 31,
                                      2000           Goodwill         Other          2001
                                 -------------------------------------------------------------
<S>                                 <C>                <C>            <C>          <C>
Natural Gas Transmission            $  299             $    -         $   5        $  304
Field Services                         507                  -           (15)          492
North American Wholesale
   Energy                               12                  -             1            13
International Energy                   457                  6           (37)          426
Other Energy Services                   46                  -            (1)           45
Other Operations                       183                  -            (8)          175
                                 -------------------------------------------------------------
   Total consolidated               $1,504             $    6         $ (55)       $1,455
----------------------------------------------------------------------------------------------
</TABLE>

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. Adoption of the new standard had no material adverse
effect on the Company's consolidated results of operations or financial
position.

Reclassifications. Certain prior period amounts have been reclassified in the
Consolidated Financial Statements and Note 5 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 2.53% to 15.0%, with maturity dates ranging from 2002
through 2027. 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 $1.8 billion in cash. Under prorating provisions 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 Company plans to
retire the commercial paper later in 2002 and replace it with permanent capital
in the form of mandatory convertible equity. The timing for the mandatory
convertible equity financing will be dependent on the market opportunities
presented and favorable market conditions. The Westcoast acquisition was
accounted for using the purchase method of accounting, and goodwill totaling
approximately $2.5 billion was recorded in the transaction.

                                        9

<PAGE>

The following unaudited pro forma consolidated financial results for the period
ended March 31, 2002 and March 31, 2001 are presented as if the acquisition had
taken place at the beginning of the periods presented.

-----------------------------------------------------------------------------
Westcoast Pro Forma Consolidated Results (in millions)
-----------------------------------------------------------------------------
                                                       Three Months Ended
                                                            March 31,
                                                   --------------------------
                                                         2002          2001
                                                   --------------------------
Income Statement Data
Operating revenues                                    $10,971       $17,780
Income before comulative effect of change in
  accounting principle                                    211           441
Cumulative effect of change in accounting
  principle, net of tax                                     -           (69)
Net income                                                211           372
-----------------------------------------------------------------------------

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).
Two components of DE&S are not part of the sale and will remain as components of
Other Energy Services. The Company will establish Duke Energy - Energy Delivery
Services, formed by the power delivery services component of DE&S, which will
continue to supply power delivery solutions to customers. Leadership of the U.S.
Department of Energy Mixed Oxide Fuel project will also remain with the Company.

DukeSolutions. On May 1, 2002, the Company completed the sale of portions of
DukeSolutions to Ameresco. Inc. The remaining portions will remain as a
component of Other Energy Services. During the first quarter of 2002, the
Company recorded a reserve of $15 million for the expected loss associated with
the sale of DukeSolutions.

4.       DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND CREDIT RISK

Commodity Cash Flow Hedges. The Company's subsidiaries 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,
consisting of 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 20
years.

For the three months ended March 31, 2002, the ineffective portion of commodity
cash flow hedges and the amount recognized for transactions that no longer
qualified as cash flow hedges were not material. As of March 31, 2002, $372
million of after-tax deferred net gains on derivative instruments were
accumulated on the 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. The Company's subsidiaries are exposed to changes
in the fair value of some unrecognized firm commitments to sell generated power
or natural gas due to market fluctuations in the underlying commodity prices.
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,
consisting of 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
23 years. For the three months ended March 31, 2002, the ineffective portion of
commodity fair value hedges was not material.

                                       10

<PAGE>

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. The Company manages its trading exposure with strict 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, commercial paper and auction rate
preferred stock. The Company manages its interest rate exposure by limiting its
variable-rate and fixed-rate exposures to percentages of total capitalization,
as set by policy, 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 months ended
March 31, 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 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, when possible, contracts are 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. For the three months ended March
31, 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 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
some customers may be similarly affected by changes in economic, regulatory or
other factors. 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.

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 March 31, 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 Corporation, the Company terminated substantially all
contracts with Enron Corporation 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
NAWE, $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.

                                       11

<PAGE>

The Company's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$19 million. Any bankruptcy claims that exceed this amount would 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 Company affiliate, Companhia de Geracao de Energia
Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A
(Elektro), a distribution company 40% 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 liquefied 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 strategic business units. Their accounting policies are
the same as those described in Note 2. Management evaluates segment performance
based on earnings before interest and taxes (EBIT) after deducting minority
interests. The following table shows how EBIT is calculated.

========================================================================
Reconciliation of Operating Income to EBIT (in millions)
------------------------------------------------------------------------
                                                  Three Months Ended
                                                        March 31,
                                              --------------------------
                                                  2002         2001
                                              --------------------------
Operating income                                   $362         $889
Plus: Other income and expenses                      47           10
                                              --------------------------
EBIT                                               $409         $899
========================================================================

EBIT is the main 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 table, EBIT includes intersegment sales at prices
representative of unaffiliated party transactions. Capital and investment
expenditures are gross of cash received from acquisitions.

                                       12

<PAGE>

<TABLE>
<CAPTION>
=========================================================================================================
Business Segment Data (in millions)
---------------------------------------------------------------------------------------------------------
                                                                               Depreciation   Capital and
                            Unaffiliated  Intersegment     Total                   and        Investment
                              Revenues      Revenues     Revenues      EBIT    Amortization  Expenditures
                            -----------------------------------------------------------------------------
<S>                            <C>           <C>         <C>           <C>        <C>          <C>
Three Months Ended
March 31, 2002
Natural Gas Transmission        $  456       $   28      $   484       $268        $ 54        $2,020
Field Services                   1,359          207        1,566         35          74           110
North American Wholesale
   Energy                        6,780           30        6,810         46          29           736
International Energy               985            1          986         67          23            81
Other Energy Services               70           66          136         (2)          1             1
Duke Ventures                       39            -           39          6           4           125
Other Operations (a)                 -          (36)         (36)       (25)          3            36
Eliminations and
     minority interests              -         (296)        (296)        14           -             -
                            -----------------------------------------------------------------------------
   Total consolidated           $9,689       $    -      $ 9,689       $409        $188        $3,109
---------------------------------------------------------------------------------------------------------

Three Months Ended
March 31, 2001
Natural Gas Transmission       $   245       $   37      $   282       $175       $  35        $   79
Field Services                   2,624          774        3,398        123          68            46
North American Wholesale
   Energy                       10,892          136       11,028        388          20           496
International Energy               498            4          502         76          25            23
Other Energy Services              104           14          118          4           3             5
Duke Ventures                       37            -           37          7           4           174
Other Operations (a)                 -           91           91         (5)          7            25
Eliminations and
     minority interests              -       (1,056)      (1,056)       131           -             -
                            -----------------------------------------------------------------------------
   Total consolidated          $14,400       $    -      $14,400       $899       $ 162        $  848
=========================================================================================================
</TABLE>

(a) 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)
-----------------------------------------------------------------------------
                                              March 31,       December 31,
                                                2002              2001
                                         ------------------------------------
Natural Gas Transmission                      $15,394           $ 5,027
Field Services                                  6,801             7,277
North American Wholesale
   Energy                                      18,299            14,005
International Energy                            5,665             5,115
Other Energy Services                             234               145
Duke Ventures                                   2,062             1,926
Other Operations and eliminations (a)             (88)            1,795
                                         ------------------------------------
   Total consolidated                         $48,367           $35,290
=============================================================================
(a)  Other operations primarily includes certain unallocated corporate costs.

                                       13

<PAGE>

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 London Interbank Offered Rate
plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these
issuances were used to manage working capital needs and to fund a portion of the
cash consideration for the Westcoast acquisition.

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 business 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.

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 2.53% to 15.0%, with
maturity dates ranging from 2002 through 2027. (See Note 3.)

7.       COMMITMENTS AND CONTINGENCIES

California Issues. Duke Energy, some of the Company's subsidiaries and three
current or former executives have been named as defendants, among other
corporate and individual defendants, in one or more of a total of six lawsuits
brought by or on behalf of electricity consumers in the State of California. The
plaintiffs seek damages as a result of the defendants' alleged unlawful
manipulation of the California wholesale electricity markets. DENA and DETM are
among 16 defendants in a class-action lawsuit (the Gordon lawsuit) filed against
generators and traders of electricity in California markets. DETM was also named
as one of numerous defendants in four additional lawsuits, including two class
actions (the Hendricks and Pier 23 Restaurant lawsuits), filed against
generators, marketers, traders and other unnamed providers of electricity in
California markets. A sixth lawsuit (the Bustamante lawsuit) was brought by the
Lieutenant Governor of the State of California and a State Assemblywoman, on
their own behalf as citizens and on behalf of the general public, and includes
Duke Energy, some of the Company's subsidiaries and three current or former
executives of Duke Energy among other corporate and individual defendants. The
Gordon and Hendricks class-action lawsuits were filed in the Superior Court of
the State of California, San Diego County, in November 2000. Three other
lawsuits were filed in January 2001, one in Superior Court, San Diego County,
and the other two in Superior Court, County of San Francisco. The Bustamante
lawsuit was filed in May 2001 in Superior Court, Los Angeles County. These
lawsuits generally allege that the defendants manipulated the wholesale
electricity markets in violation of state laws against unfair and unlawful
business practices and state antitrust laws. The plaintiffs seek aggregate
damages of billions of dollars. The lawsuits seek the refund of alleged
unlawfully obtained revenues for electricity sales and, in four lawsuits, an
award of treble damages. These suits have been consolidated before a state court
judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master
Amended Complaint on March 8, 2002, which adds additional defendants. The claims
against the defendants are similar to those in the original complaints. The
court has approved a schedule which calls for class certification motions to be
filed by October 1, 2002 in the class action lawsuits. Trial has been scheduled
for March 1, 2004. While these matters are in their earliest stages, management
believes, based on its analysis of the facts and the asserted claims, that their
resolution will have no material adverse effect on the Company's consolidated
results of operations, cash flows or financial position.

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
issues.

                                       14

<PAGE>

Regulatory Matters. In November 2001, Nevada Power Company and Sierra Pacific
Power Company (collectively, the Power Companies) filed a complaint with the
FERC against DETM. The complaint requests the FERC to mitigate prices in sales
contracts between the Company and Nevada Power, and the Company and Sierra
Pacific that were entered into between December 7, 2000 and June 20, 2001. The
Power Companies allege that the contract prices are unjust and unreasonable
because they were entered into during a period that the FERC determined the
California market to be dysfunctional and uncompetitive, and that the California
market influenced the contract prices. In April 2002, the FERC issued an order
which provides for an evidentiary hearing, establishes refund dates, and
requires the parties to participate in settlement negotiations. In the order,
the FERC also estimated a final decision by July 2003. While this matter is in
its earliest stages, management believes, based on its analysis of facts and the
asserted claims, that the resolution will have no material adverse effect on the
Company's consolidated results of operations, cash flows or financial position.

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 March 31, 2002, net income was $174 million compared
to $319 million for 2001. The decrease was due primarily to a 55% decrease in
earnings before interest and taxes (EBIT), as described below. The current-year
EBIT decrease on a comparative basis was partially offset by the prior year's
one-time net-of-tax charge of $69 million. This one-time charge was 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 comparative decrease in EBIT was a $128 million decrease in minority
interest expense, as discussed in the following sections.

Operating income was $362 million and EBIT was $409 million for the three months
ended March 31, 2002. This compares to operating income of $889 million and EBIT
of $899 million for the same period in 2001. 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.

                                       15

<PAGE>

============================================================================
Reconciliation of Operating Income to Net Income (in millions)
----------------------------------------------------------------------------
                                                     Three Months Ended
                                                          March 31,
                                              ------------------------------
                                                    2002          2001
                                              ------------------------------
Operating income                                     $362          $889
Other income and expenses                              47            10
                                              ------------------------------
EBIT                                                  409           899
Interest expense                                      131           145
Minority interest expense                              21           149
                                              ------------------------------
Earnings before income taxes                          257           605
Income taxes                                           83           217
                                              ------------------------------
Income before cumulative
  effect of change in accounting                      174           388
    principle
Cumulative effect of change in accounting
  principle, net of tax                                 -           (69)
                                              ------------------------------
Net income                                           $174          $319
============================================================================

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

=========================================================================
EBIT by Business Segment (in millions)
-------------------------------------------------------------------------
                                                  Three Months Ended
                                                      March 31,
                                             ----------------------------
                                                  2002           2001
                                             ----------------------------
Natural Gas Transmission                          $268           $175
Field Services                                      35            123
North American Wholesale Energy                     46            388
International Energy                                67             76
Other Energy Services                               (2)             4
Duke Ventures                                        6              7
Other Operations                                   (25)            (5)
EBIT attributable to minority interests             14            131
                                             ----------------------------
Consolidated EBIT                                 $409           $899
=========================================================================

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

                                       16

<PAGE>

Natural Gas Transmission

=========================================================================
                                                   Three Months Ended
                                                       March 31,
                                            -----------------------------
(in millions, except where noted)                2002           2001
-------------------------------------------------------------------------
Operating revenues                                $484           $282
Operating expenses                                 218            107
                                            -----------------------------
Operating income                                   266            175
Other income, net of expenses                        5              -
Minority interest expense                            3              -
                                            -----------------------------
EBIT                                              $268           $175
                                            =============================

Proportional throughput, TBtu (a)                  759            548
=========================================================================
(a) Trillion British thermal units

For the three months ended March 31, 2002, EBIT for Natural Gas Transmission
increased $93 million compared to the same period in 2001. This increase
primarily resulted from $62 million in earnings from the natural gas
transmission and distribution assets acquired as a part of the acquisition of
Westcoast Energy, Inc. (Westcoast) in March 2002. (See Note 3 to the
Consolidated Financial Statements.) Also contributing to the increase in EBIT
was a $14 million gain on the sale of a portion of Natural Gas Transmission's
limited partnership interest in Northern Border Partners, LP, which owns a
general partnership interest in Northern Border Pipeline Company.

Field Services

<TABLE>
<CAPTION>
=========================================================================================
                                                                 Three Months Ended
                                                                     March 31,
                                                            -----------------------------
(in millions, except where noted)                               2002            2001
-----------------------------------------------------------------------------------------
<S>                                                            <C>            <C>
Operating revenues                                             $1,566         $3,398
Operating expenses                                              1,523          3,219
                                                            -----------------------------
Operating income                                                   43            179
Other income, net of expenses                                       -              -
Minority interest expense                                           8             56
                                                            -----------------------------
EBIT                                                           $   35         $  123
                                                            =============================

Natural gas gathered and processed/transported, TBtu/d (a)        8.4            8.2
Natural gas liquid (NGL) production, MBbl/d (b)                 388.6          371.1
Natural gas marketed, TBtu/d                                      1.6            1.6
Average natural gas price per MMBtu (c)                         $2.32          $7.09
Average NGL price per gallon (d)                                $0.31          $0.60
=========================================================================================
</TABLE>

(a) Trillion British thermal units per day
(b) Thousand barrels per day
(c) Million British thermal units
(d) Does not reflect results of commodity hedges

EBIT for Field Services decreased $88 million for the three months ended March
31, 2002 compared to the same period in 2001, due primarily to the decrease in
commodity prices. The decrease was driven by a $4.77 per MMBtu decrease in the
average natural gas prices and a $0.29 per gallon decrease in the average NGL
prices. Partially offsetting the decrease in commodity prices were increased
contributions of approximately $15 million from the 2001 acquisitions of
Canadian Midstream Services, Ltd., northeast propane terminal and marketing
assets, and additional interests in three offshore Gulf of Mexico partnerships.

                                       17

<PAGE>

North American Wholesale Energy (NAWE)

===========================================================================
                                                   Three Months Ended
                                                       March 31,
                                              -----------------------------
(in millions, except where noted)                 2002           2001
------------------------------------------------------------ --------------
Operating revenues                               $6,810        $11,028
Operating expenses                                6,764         10,562
                                              -----------------------------
Operating income                                     46            466
Other income (loss), net of expenses                 (1)           (10)
Minority interest (benefit) expense                  (1)            68
                                              -----------------------------
EBIT                                             $   46        $   388
                                              =============================

Natural gas marketed, TBtu/d                       13.7           13.6
Electricity marketed and traded, GWh (a)        108,220         44,617
Proportional megawatt capacity in operation       7,515          5,064
Proportional megawatt capacity owned (b)         18,605         10,054
===========================================================================
(a) Gigawatt-hours
(b) Includes under construction or under contract at period end

For the three months ended March 31, 2002, NAWE's EBIT decreased $342 million
compared to the same period in 2001. Increases of 48% in the proportional
megawatt capacity of generation assets in operation and 143% in the marketing
and trading of electricity volumes were significantly offset by decreased
origination activities and trading margins. Last year's results were driven by
unusually high natural gas and power prices and volatility levels, especially in
the western U.S. This year's results reflect a return to more normal commodity
pricing and volatility. In 2002, NAWE also held several short positions during a
period of rising market prices (contracts under which a trader has agreed to
sell a commodity at a future date for a specific price) which also contributed
to the decrease in EBIT. Partially offsetting these decreases were lower
variable compensation costs related to the trading activities. Changes in the
ownership percentage of NAWE's waste-to-energy plants and decreased earnings at
Duke Energy Trading and Marketing, LLC (DETM) resulted in a $69 million decrease
in minority interest expense compared to the prior year.

                                       18

<PAGE>

International Energy

<TABLE>
<CAPTION>
=======================================================================================
                                                                  Three Months Ended
                                                                       March 31,
                                                               ------------------------
(in millions, except where noted)                                  2002       2001
---------------------------------------------------------------------------------------
<S>                                                                 <C>        <C>
Operating revenues                                                  $986       $502
Operating expenses                                                   927        428
                                                               ------------------------
Operating income                                                      59         74
Other income, net of expenses                                         13          9
Minority interest expense                                              5          7
                                                               ------------------------
EBIT                                                                $ 67       $ 76
                                                               ========================

Proportional megawatt capacity in operation                        4,705      4,199
Proportional megawatt capacity owned (a)                           5,748      4,847
Proportional maximum pipeline capacity in operation (a),
   MMcf/d (b)                                                        363        255
Proportional maximum pipeline capacity owned (a), MMcf/d (b)         363        363
=======================================================================================
</TABLE>

(a) Includes under construction or under contract at period end
(b) Million cubic feet per day

International Energy's EBIT decreased $9 million for the three months ended
March 31, 2002 compared to the same period in 2001, due primarily to decreased
earnings from Latin America investments and European operations. The Latin
American operations were affected by lower demand in Brazil due to the
government's mandatory energy rationing, which was in effect until mid-March
2002. The European operations were affected by lower trading margins and lower
product prices. The corresponding 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
                                               March 31,
                                     -----------------------------
(in millions)                            2002            2001
------------------------------------------------------------------
Operating revenues                        $136           $118
Operating expenses                         138            114
                                     -----------------------------
EBIT                                      $ (2)          $  4
==================================================================

For the three months ended March 31, 2002, EBIT for Other Energy Services
decreased $6 million compared to the same period in 2001. 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 decrease in EBIT as compared to the prior year was due primarily to a
current-year $15 million reserve for the expected loss associated with the sale
of DukeSolutions, Inc. This loss was partially offset by project income at
Duke/Fluor Daniel.

                                       19

<PAGE>

Duke Ventures

==================================================================
                                              Three Months Ended
                                                   March 31,
                                     -----------------------------
(in millions)                                2002           2001
------------------------------------------------------------------
Operating revenues                            $39            $37
Operating expenses                             34             30
                                     -----------------------------
Operating income                                5              7
Minority interest benefit                      (1)             -
                                     -----------------------------
EBIT                                          $ 6            $ 7
==================================================================

EBIT for Duke Ventures decreased $1 million for the three months ended March 31,
2002 compared to the same period in 2001.

Other Impacts on Net Income

For the three months ended March 31, 2002, interest expense decreased $14
million compared to the same period in 2001, due primarily to lower interest
rates on commercial paper.

Minority interest expense decreased $128 million for the three months ended
March 31, 2002 compared to the same period in 2001. Minority interest expense
includes expense related to regular distributions on preferred securities of the
Company and its subsidiaries. This expense decreased $11 million for the three
months ended March 31, 2002 due 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.

Minority interest expense as shown and discussed in the preceding business
segment EBIT discussions 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 $117 million for the three month period due to decreased
income from Field Services' joint venture with Phillips Petroleum, changes in
the ownership percentage of NAWE's waste-to-energy plants and decreased earnings
at DETM, NAWE's joint venture with Exxon Mobil Corporation.

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 $1,407 million in 2002 when compared
to the same period in 2001. The increase is due primarily to the change in the
net unrealized mark-to-market and hedging transactions resulting from increased
cash earnings in the first quarter of 2002 versus the same period in 2001. As a
result of the increased volatility and higher prices in the western U.S. for
power in the first quarter of 2001, the Company experienced a higher level of
non-cash earnings from mark-to-market transactions as compared to first quarter
2002.

Investing Cash Flows

Net cash used in investing activities increased $2,261 million in 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). Capital and investment expenditures
increased $494 million in 2002 compared to 2001. The increase reflects
additional expansion and development

                                     20

<PAGE>

expenditures (especially related to NAWE's generating facilities),
refurbishment and upgrades to existing assets and minor acquisitions of
businesses and assets.

Financing Cash Flows

The Company's growth initiatives, along with debt repayments and operating
requirements are expected to be funded by cash from operations, debt and capital
market financings, project financings and proceeds from the sale of assets.
These financing opportunities are dependent upon the market opportunities
presented and favorable market conditions. Additionally, internal cash
generation should fund approximately half of the capital needs. Management
believes the Company has adequate financial resources to meet its future needs.

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 London Interbank Offered Rate
plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these
issuances were used to manage working capital needs and to fund a portion of the
cash consideration for the Westcoast acquisition.

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 business 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.

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
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 2.53% to 15.0%, with maturity
dates ranging from 2002 through 2027. In addition to the debt assumed, Westcoast
and Union Gas Limited have operating credit facilities of 600 million Canadian
dollars and 715 million Canadian dollars, respectively. Borrowings under each of
these facilities are subject to and dependent upon the senior unsecured ratings
of Westcoast (currently rated A for Dominion Bond Rating Service (DBRS) and A+
for Standard & Poor's) and Union Gas (currently rated A(low) for DBRS and A+ for
Standard & Poor's ). For the Westcoast credit facility, a material adverse
change could occur if the ratings for Westcoast fall below a BBB(low) at DBRS or
a BB+ at Standard & Poor's, although a change in ratings is not in and of itself
a material adverse change. 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 the 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 $1.8 billion in cash. Under prorating provisions of
the acquisition agreement that ensure 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

                                     21

<PAGE>

commercial paper. The Company plans to retire the commercial paper later in 2002
and replace it with permanent capital in the form of mandatory convertible
equity. The timing for the mandatory convertible equity will be dependent on the
market opportunities presented and favorable market conditions. The Westcoast
acquisition was accounted for using the purchase method of accounting, and
goodwill totaling approximately $2.5 billion was recorded in the transaction.

Under its commercial paper, medium-term notes and extendible commercial notes
(ECNs) programs, the Company had the ability to borrow up to $6,167 million at
March 31, 2002 compared with $3,608 million at December 31, 2001. These programs
do not have termination dates. The following table summarizes the commercial
paper, medium-term notes and ECNs as of March 31, 2002.

<TABLE>
<CAPTION>
==================================================================================================
                                                        Duke
                     Duke Capital     Duke Energy      Energy      Westcoast   Union Gas
(in millions)        Corporation    Field Services  International   Energy      Limited    Total
--------------------------------------------------------------------------------------------------
<S>                    <C>              <C>            <C>           <C>         <C>      <C>
Commercial Paper       $2,550           $650           $400(a)       $376        $470     $4,446
Medium-term notes           -              -              -           470         251        721
ECNs                    1,000              -              -             -           -      1,000
                     -----------------------------------------------------------------------------
Total                  $3,550           $650           $400          $846        $721     $6,167
==================================================================================================
</TABLE>

(a) Includes ability to issue medium term notes

The total amount of the Company's bank credit facilities was $6,186 million as
of March 31, 2002 compared with $3,406 million as of December 31, 2001. Some of
the credit facilities support the issuance of commercial paper and as a result,
the issuance of commercial paper reduces the amount available under these credit
facilities. As of March 31, 2002, $3,335 million was outstanding in the form of
commercial paper, medium-term notes and ECNs, and $40 million of borrowings were
outstanding under the bank credit facilities. The credit facilities expire from
2002 to 2005 and are not subject to minimum cash requirements.

As of March 31, 2002, the Company and its subsidiaries had effective Securities
and Exchange Commission shelf registrations for up to $1,500 million in gross
proceeds from debt and other securities. Such securities may be issued as senior
notes, subordinated notes and trust preferred securities. In addition, Westcoast
and its subsidiaries had $439 million of unused Canadian debt capacity.

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. Duke Energy'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 Financial Accounting Standards Board's (FASB) Emerging Issues Task
Force (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).

                                     22

<PAGE>

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 matrix 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. Correlation and
volatility are two 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. While the Company uses industry best
practices to develop its pricing models, 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). While 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, an
option contract for the purchase of electricity qualifies 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. Of the total estimated value of this portfolio,
approximately 80% is attributed to the anticipated value of merchant generation
facility capacity owned or controlled by the Company. This portion of the value
of the merchant generation portfolio is anticipated to be realized in future
periods as the generation facilities are dispatched. A portion of this future
value is secured by hedge contracts. Of the unhedged capacity, dispatch
performance, and in some cases price, has been further secured through 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

                                     23

<PAGE>

recognition until contract performance occurs. The remaining percentage of the
total estimated value of the merchant generation 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. The table below represents the value by year of the
Company's North American merchant generation portfolio. It does not include the
value of trading positions, or hedges of other commodity risks or exposures.

<TABLE>
<CAPTION>
=====================================================================================================
North American Merchant Generation Portfolio Value as of March 31, 2002 (in millions)
-----------------------------------------------------------------------------------------------------
                                                             Maturity in 2005          Total
Maturity in 2002     Maturity in 2003    Maturity in 2004    and Thereafter (a)   Portfolio Value
-----------------------------------------------------------------------------------------------------
      <S>                   <C>                 <C>                 <C>                 <C>
      $747                  $785                $895                $4,378              $6,805
=====================================================================================================
</TABLE>

(a) For purposes of calculating total portfolio value, model valuations were
calculated through 2010.

As of March 31, 2002, the portion hedged of NAWE's expected output of its
merchant generation portfolio was 74% for 2003, 60% for 2004 and 59% for 2005
through derivative contracts such as forward natural gas purchases and forward
power sales.

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 utilizing a Value-at-Risk base 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) to simulate
forward price curves in the energy markets to estimate the potential favorable
or unfavorable impact of one day's price movement on the existing portfolio. 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.

<TABLE>
<CAPTION>
=============================================================================================================
Daily Earnings at Risk (in millions)
-------------------------------------------------------------------------------------------------------------
                      Estimated Average      Estimated Average
                      One-Day Impact on      One-Day Impact on     High One-Day Impact    Low One-Day Impact
                    EBIT for 1st Quarter    EBIT for 1st Quarter     on EBIT for 1st        on EBIT for 1st
                           2002 (a)                2001               Quarter 2002            Quarter 2002
-------------------------------------------------------------------------------------------------------------
<S>                         <C>                    <C>                    <C>                    <C>
Calculated DER              $14                    $27                    $26                    $6
=============================================================================================================
</TABLE>

(a) Amount 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.

                                     24

<PAGE>

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 first quarter of
2002.

<TABLE>
<CAPTION>
============================================================================================
Changes in Fair Value of Trading Contracts (in millions)
--------------------------------------------------------------------------------------------
<S>                                                                                  <C>
Fair value of contracts outstanding at the beginning of the year                     $939
Contracts realized or otherwise settled during the period                             (77)
Fair value of contracts entered into during the period                                 48
Changes in fair value amounts attributable to changes in valuation techniques          36
Other changes in fair values                                                         (105)
                                                                                 -----------
Fair value of contracts outstanding at the end of the period                         $841
============================================================================================
</TABLE>

For the quarter ended March 31, 2002, the unrealized net loss recognized in
operating income was $61 million compared to a $579 million gain for the first
quarter of 2001. 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. At March 31, 2002, the Company held cash or letters
of credit of $797 million to secure such future performance, and had deposited
with counterparties $96 million of such collateral to secure its obligations to
provide such future services. Collateral amounts held or posted 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 held collateral and post additional collateral should price movements
adversely impact the value of open contracts or positions.

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 March 31, 2002.

<TABLE>
<CAPTION>
============================================================================================================
Fair Value of Trading Contracts as of March 31, 2002 (in millions)
------------------------------------------------------------------------------------------------------------
                                                                                  Maturity in
                                      Maturity in    Maturity in   Maturity in      2005 and      Total Fair
Sources of Fair Value                     2002           2003          2004        Thereafter        Value
------------------------------------------------------------------------------------------------------------
<S>                                       <C>            <C>           <C>             <C>            <C>
Prices supported by quoted
   market prices and other
   external sources                       $157           $144          $ 81            $ 11           $393
Prices based on models and other
   valuation methods                        25             13            51             359            448
------------------------------------------------------------------------------------------------------------
Total                                     $182           $157          $132            $370           $841
============================================================================================================
</TABLE>

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

                                     25

<PAGE>

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 value of the Company's trading portfolio valuation adjustments for
liquidity, credit and cost of service is 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 23 years; however, since 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 or 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's qualifying hedge positions at a point in time is
not necessarily indicative of the value realized when such contracts settle.

                                     26

<PAGE>

<TABLE>
<CAPTION>
====================================================================================================
Fair Value of Hedge Position Contracts as of March 31, 2002 (in millions)
----------------------------------------------------------------------------------------------------
                                                             Maturity in 2005          Total
Maturity in 2002     Maturity in 2003    Maturity in 2004     and Thereafter      Contract Value
----------------------------------------------------------------------------------------------------
    <S>                   <C>                 <C>                   <C>                 <C>
    $412                  $139                $102                  $163                $816
====================================================================================================
</TABLE>

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 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 some customers may be
similarly affected by changes in economic, regulatory or other factors. 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.

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 March 31, 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 Corporation, the Company terminated substantially all
contracts with Enron Corporation 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
NAWE, $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 are likely to exceed
$19 million. Any bankruptcy claims that exceed this amount would 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 Company affiliate, Companhia de Geracao

                                     27

<PAGE>

de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e
Servicos S/A (Elektro), a distribution company 40% 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 liquefied 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, commercial paper and auction rate market preferred stock. The Company
manages its interest rate exposure by limiting its variable-rate and fixed-rate
exposures to percentages of total capitalization, as set by policy, 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.)

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, when possible,
transactions are 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.

Since 1991, the Argentine peso has been pegged to the U.S. dollar at a fixed 1:1
exchange ratio. In December 2001, the Argentine government imposed a restriction
that limited cash withdrawals above a certain amount and foreign money
transfers. Financial institutions were allowed to conduct limited activity as a
bank and exchange holiday was announced, and currency exchange activity was
essentially halted. In January 2002, the Argentine government announced the
creation of a dual-currency system. Subsequently, however, the Argentine
government has decided to use a free-floating currency.

The Company's investment in Argentina was U.S. dollar functional as of December
31, 2001. Once a functional currency determination has been made, that
determination must be adhered to consistently, unless significant changes in
economic factors indicate that the entity's functional currency has changed. The
recent events in Argentina require a change. In January 2002, the functional
currency of the Company's investment in Argentina changed from the U.S. dollar
to the Argentine peso. In compliance with SFAS No. 52, "Foreign Currency
Translation," the change in functional currency will be made prospectively.
Management believes that the events in Argentina will have no material adverse
effect on the Company's future consolidated results of operations, cash flows or
financial position.

CURRENT ISSUES

California Issues. Duke Energy, some of the Company's subsidiaries and three
current or former executives have been named as defendants, among other
corporate and individual defendants, in one or more of a total of six lawsuits
brought by or on behalf of electricity consumers in the State of California. The
plaintiffs seek damages as a result of the defendants' alleged unlawful
manipulation of the California wholesale electricity markets. Duke Energy North
America, LLC (DENA) and DETM are among 16 defendants in a class-action lawsuit
(the Gordon lawsuit) filed against generators and traders of electricity in
California markets. DETM was also named as one of numerous defendants in four
additional lawsuits,

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including two class actions (the Hendricks and Pier 23 Restaurant lawsuits),
filed against generators, marketers, traders and other unnamed providers of
electricity in California markets. A sixth lawsuit (the Bustamante lawsuit) was
brought by the Lieutenant Governor of the State of California and a State
Assemblywoman, on their own behalf as citizens and on behalf of the general
public, and includes Duke Energy, some of the Company's subsidiaries and three
current or former executives of Duke Energy among other corporate and
individual defendants. The Gordon and Hendricks class-action lawsuits were
filed in the Superior Court of the State of California, San Diego County, in
November 2000. Three other lawsuits were filed in January 2001, one in Superior
Court, San Diego County, and the other two in Superior Court, County of San
Francisco. The Bustamante lawsuit was filed in May 2001 in Superior Court, Los
Angeles County. These lawsuits generally allege that the defendants manipulated
the wholesale electricity markets in violation of state laws against unfair and
unlawful business practices and state antitrust laws. The plaintiffs seek
aggregate damages of billions of dollars. The lawsuits seek the refund of
alleged unlawfully obtained revenues for electricity sales and, in four
lawsuits, an award of treble damages. These suits have been consolidated before
a state court judge in San Diego. The plaintiffs in the six lawsuits filed a
joint Master Amended Complaint on March 8, 2002, which adds additional
defendants. The claims against the defendants are similar to those in the
original complaints. The court has approved a schedule which calls for class
certification motions to be filed by October 1, 2002 in the class action
lawsuits. Trial has been scheduled for March 1, 2004. While these matters are
in their earliest stages, management believes, based on its analysis of the
facts and the asserted claims, that their resolution will have no material
adverse effect on the Company's consolidated results of operations, cash flows
or financial position.

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
issues.

Regulatory Matters. In November 2001, Nevada Power Company and Sierra Pacific
Power Company (collectively, the Power Companies) filed a complaint with the
Federal Energy Regulatory Commission (FERC) against DETM. The complaint requests
the FERC to mitigate prices in sales contracts between the Company and Nevada
Power, and the Company and Sierra Pacific that were entered into between
December 7, 2000 and June 20, 2001. The Power Companies allege that the contract
prices are unjust and unreasonable because they were entered into during a
period that the FERC determined the California market to be dysfunctional and
uncompetitive, and that the California market influenced the contract prices. In
April 2002, the FERC issued an order which provides for an evidentiary hearing,
establishes refund dates, and requires the parties to participate in settlement
negotiations. In the order, the FERC also estimated a final decision by July
2003. While this matter is in its earliest stages, management believes, based on
its analysis of facts and the asserted claims, that the resolution will have no
material adverse effect on the Company's consolidated results of operations,
cash flows or financial position.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For additional information concerning litigation and other contingencies, see
Note 7 to the Consolidated Financial Statements, "Commitments and
Contingencies," and Item 3, "Legal Proceedings," 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
------

10.1       $500,000,000 364-Day Credit Agreement dated as of April 18, 2002,
           among Duke Capital Corporation, the Banks listed therein and Bank
           One, NA, as Administrative Agent (filed with Form 10-Q of Duke Energy
           Corporation for the quarter ended March 31, 2002, File No. 1-4928, as
           Exhibit 10).

(b)    Reports on Form 8-K

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

         A Current Report on Form 8-K filed on March 29, 2002 contained
disclosures under Item 2, Acquisition or Disposition of Assets and Item 7,
Financial Statements, Pro forma Financial Information and Exhibits.

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SIGNATURES

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

                                               DUKE CAPITAL CORPORATION

May 15, 2002                                   /s/  Robert P. Brace
                                               -------------------------------
                                               Robert P. Brace
                                               Vice President and
                                               Chief Financial Officer

May 15, 2002                                   /s/  Keith G. Butler
                                               -------------------------------
                                               Keith G. Butler
                                               Controller

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