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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended March 31, 2003 Commission File Number 0-23977
DUKE CAPITAL CORPORATION
(Exact name of Registrant as Specified in its Charter)
Delaware 51-0282142
(State or Other Jurisdiction (IRS Employer
of Incorporation) Identification No.)
526 South Church Street
Charlotte, NC 28202-1904
(Address of Principal Executive Offices)
(Zip code)
704-594-6200
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes (x) No( )
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ( ) No (x)
All of the Registrant's common shares are directly owned by Duke Energy
Corporation (File No. 1-4928), which files reports and proxy materials pursuant
to the Securities Exchange Act of 1934.
Indicate the number of shares outstanding of each of the Issuer's classes of
common stock, as of the latest practicable date.
Number of shares of Common Stock, without par value, outstanding at April 30,
2003........1,010
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DUKE CAPITAL CORPORATION
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2003
INDEX
Item Page
- ---- ----
PART I. FINANCIAL INFORMATION
1. Financial Statements .................................................................................. 1
Consolidated Statements of Income for the Three Months Ended March 31, 2003 and 2002 .............. 1
Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002 ............................ 2
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002 .......... 4
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2003
and 2002 ........................................................................................ 5
Notes to Consolidated Financial Statements ........................................................ 6
2. Management's Discussion and Analysis of Results of Operations and Financial Condition ................. 23
3. Quantitative and Qualitative Disclosures about Market Risk ............................................ 33
4. Controls and Procedures ............................................................................... 33
PART II. OTHER INFORMATION
1. Legal Proceedings ..................................................................................... 34
6. Exhibits and Reports on Form 8-K ...................................................................... 34
Signatures ............................................................................................ 35
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Duke Capital Corporation's reports, filings and other public announcements may
contain or incorporate by reference statements that do not directly or
exclusively relate to historical facts. Such statements are "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995. You can typically identify forward-looking statements by the use of
forward-looking words, such as "may," "will," "could," "project," "believe,"
"anticipate," "expect," "estimate," "continue," "potential," "plan," "forecast"
and other similar words. Those statements represent the Company's intentions,
plans, expectations, assumptions and beliefs about future events and are subject
to risks, uncertainties and other factors. Many of those factors are outside the
Company's control and could cause actual results to differ materially from the
results expressed or implied by those forward-looking statements. Those factors
include:
. State, federal and foreign legislative and regulatory initiatives that
affect cost and investment recovery, have an impact on rate structures,
and affect the speed at and degree to which competition enters the
electric and natural gas industries
. The outcomes of litigation and regulatory investigations, proceedings or
inquiries
. Industrial, commercial and residential growth in the Company's service
territories
. The weather and other natural phenomena
. The timing and extent of changes in commodity prices, interest rates and
foreign currency exchange rates
. General economic conditions, including any potential effects arising from
terrorist attacks, the situation in Iraq and any consequential
hostilities or other hostilities
. Changes in environmental and other laws and regulations to which the
Company and its subsidiaries are subject or other external factors over
which the Company has no control
i
. The results of financing efforts, including the Company's ability to
obtain financing on favorable terms, which can be affected by various
factors, including the Company's credit ratings and general economic
conditions
. Lack of improvement or further declines in the market prices of equity
securities and resultant cash funding requirements for the Company's
defined benefit pension plans
. The level of creditworthiness of counterparties to the Company's
transactions
. The amount of collateral required to be posted from time to time in the
Company's transactions
. Growth in opportunities for the Company's business units, including the
timing and success of efforts to develop domestic and international
power, pipeline, gathering, processing and other infrastructure projects
. The performance of electric generation, pipeline and gas processing
facilities
. The extent of success in connecting natural gas supplies to gathering and
processing systems and in connecting and expanding gas and electric
markets and
. The effect of accounting pronouncements issued periodically by accounting
standard-setting bodies
In light of these risks, uncertainties and assumptions, the events described in
the forward-looking statements might not occur or might occur to a different
extent or at a different time than the Company has described. The Company
undertakes no obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In millions)
Three Months Ended
March 31,
--------------------
2003 2002
-------- --------
(Restated)
Operating Revenues
Sales of natural gas and petroleum products $ 3,404 $ 1,009
Transportation and storage of natural gas 436 326
Electric generation 518 494
Trading and marketing net (loss) margin (59) 202
Other 144 177
-------- --------
Total operating revenues 4,443 2,208
-------- --------
Operating Expenses
Natural gas and petroleum products purchased 3,020 907
Purchased power 122 144
Other operation and maintenance 409 569
Depreciation and amortization 267 188
Property and other taxes 67 61
-------- --------
Total operating expenses 3,885 1,869
-------- --------
Operating Income 558 339
-------- --------
Other Income and Expenses
Equity in earnings of unconsolidated affiliates 34 9
Gains on sale of equity investments 14 14
Other income and expenses, net 23 56
-------- --------
Total other income and expenses 71 79
Interest Expense 278 140
Minority Interest Expense 41 21
-------- --------
Earnings Before Income Taxes 310 257
Income Taxes 103 83
-------- --------
Income Before Cumulative Effect of Change in Accounting Principles 207 174
Cumulative Effect of Change in Accounting Principles, net of tax (52) --
-------- --------
Net Income $ 155 $ 174
======== ========
See Notes to Consolidated Financial Statements.
1
CONSOLIDATED BALANCE SHEETS
(In millions)
March 31,
2003 December 31,
(unaudited) 2002
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 972 $ 814
Receivables 7,322 6,549
Inventory 494 666
Unrealized gains on mark-to-market and hedging transactions 2,189 2,013
Other 852 717
----------- ------------
Total current assets 11,829 10,759
----------- ------------
Investments and Other Assets
Investments in unconsolidated affiliates 2,110 2,074
Goodwill, net of accumulated amortization 3,730 3,747
Notes receivable 463 589
Unrealized gains on mark-to-market and hedging transactions 2,151 2,173
Other 2,081 2,156
----------- ------------
Total investments and other assets 10,535 10,739
----------- ------------
Property, Plant and Equipment
Cost 30,022 29,238
Less accumulated depreciation and amortization 4,205 4,026
----------- ------------
Net property, plant and equipment 25,817 25,212
----------- ------------
Regulatory Assets and Deferred Debits 918 855
----------- ------------
Total Assets $ 49,099 $ 47,565
=========== ============
See Notes to Consolidated Financial Statements.
2
CONSOLIDATED BALANCE SHEETS
(In millions)
March 31,
2003 December 31,
(unaudited) 2002
----------- ------------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 6,763 $ 5,647
Notes payable and commercial paper 1,060 683
Taxes accrued 239 --
Interest accrued 236 236
Current maturities of long-term debt 670 1,148
Unrealized losses on mark-to-market and hedging transactions 1,828 1,744
Other 1,582 1,538
----------- ------------
Total current liabilities 12,378 10,996
----------- ------------
Long-term Debt 15,456 15,703
----------- ------------
Deferred Credits and Other Liabilities
Deferred income taxes 3,324 3,222
Unrealized losses on mark-to-market and hedging transactions 1,307 1,439
Other 1,556 1,395
----------- ------------
Total deferred credits and other liabilities 6,187 6,056
----------- ------------
Guaranteed Preferred Beneficial Interests in Subordinated
Notes of Duke Capital Corporation 825 825
----------- ------------
Minority Interests 1,640 1,904
----------- ------------
Common Stockholder's Equity
Common stock, no par, 3,000 shares authorized,
1,010 shares outstanding -- --
Paid-in capital 7,633 7,545
Retained Earnings 4,906 4,748
Accumulated other comprehensive income (loss) 74 (212)
----------- ------------
Total common stockholder's equity 12,613 12,081
----------- ------------
Total Liabilities and Stockholder's Equity $ 49,099 $ 47,565
=========== ============
See Notes to Consolidated Financial Statements.
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
Three Months Ended
March 31,
--------------------
2003 2002
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 155 $ 174
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and amortization 267 190
Cumulative effect of change in accounting principle 52 --
Gains on sales of equity investment (14) (14)
Deferred income taxes 14 (40)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions (105) 233
Receivables (933) 1,882
Inventory 167 90
Other current assets (196) (201)
Increase (decrease) in
Accounts payable 1,116 (510)
Taxes accrued 231 9
Other current liabilities 101 (600)
Other, assets (3) 159
Other, liabilities 131 (186)
-------- --------
Net cash provided by operating activities 983 1,186
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures, net of cash acquired (442) (1,023)
Investment expenditures (77) (319)
Acquisition of Westcoast Energy Inc., net of cash acquired -- (1,690)
Proceeds from the sales of subsidiaries, equity investments and assets 226 23
Notes receivable 80 7
Other 144 (8)
-------- --------
Net cash used in investing activities (69) (3,010)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 117 1,352
Payments for the redemption of long-term debt (582) (406)
Net change in notes payable and commercial paper (141) 612
Contributions from minority interests 593 733
Distributions to minority interests (837) (825)
Capital contributions from parent 100 250
Other (6) (29)
-------- --------
Net cash (used in) provided by financing activities (756) 1,687
-------- --------
Net increase (decrease) in cash and cash equivalents 158 (137)
Cash and cash equivalents at beginning of period 814 263
-------- --------
Cash and cash equivalents at end of period $ 972 $ 126
======== ========
Supplemental Disclosures
Cash paid for interest, net of amount capitalized $ 275 $ 91
Cash (refund of) paid for income taxes $ (43) $ 73
Acquisition of Westcoast Energy Inc.
Fair value of assets acquired $ -- $ 9,487
Liabilities assumed, including debt and minority interests -- 8,382
Capital contribution from parent from issuance of Duke Energy common stock -- 1,797
See Notes to Consolidated Financial Statements
4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In millions)
Three Months Ended
March 31,
--------------------
2003 2002
-------- --------
Net Income $ 155 $ 174
Other comprehensive income
Foreign currency translation adjustment 164 (24)
Net unrealized gains on cash flow hedges 269 435
Reclassification into earnings (90) (197)
-------- --------
Other comprehensive income, before income taxes 343 214
Income tax expense related to items of other comprehensive income (57) (75)
-------- --------
Total other comprehensive income 286 139
-------- --------
Total Comprehensive Income $ 441 $ 313
======== ========
See Notes to Consolidated Financial Statements
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Duke Capital Corporation (collectively with its subsidiaries, the Company) is a
wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as
the parent of certain of Duke Energy's non-utility and other operations. The
Company provides financing and credit enhancement services for its subsidiaries
and conducts its operations through the business segments described below.
Natural Gas Transmission provides transportation and storage of natural gas for
customers throughout the East Coast and Southern U.S., and in Canada. Natural
Gas Transmission also provides gas sales and distribution service to retail
customers in Ontario and Western Canada, and gas gathering and processing
services to customers in Western Canada. Natural Gas Transmission does business
primarily through Duke Energy Gas Transmission Corporation. Duke Energy Gas
Transmission's natural gas transmission and storage operations in the U.S. are
subject to the Federal Energy Regulatory Commission's (FERC's) and the Texas
Railroad Commission's rules and regulations, while natural gas gathering,
processing, transmission, distribution and storage operations in Canada are
subject to the rules and regulations of the National Energy Board, the Ontario
Energy Board and the British Columbia Utilities Commission.
Field Services gathers, compresses, treats, processes, transports, trades and
markets, and stores natural gas; and produces, transports, trades and markets,
and stores natural gas liquids. It conducts operations primarily through Duke
Energy Field Services, LLC (DEFS), which is approximately 30% owned by
ConocoPhillips and approximately 70% owned by the Company. Field Services
gathers natural gas from production wellheads in Western Canada and 11
contiguous states in the U.S. Those systems serve major natural gas-producing
regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian
Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well
as onshore and offshore Gulf Coast areas.
Duke Energy North America (DENA) develops, operates and manages merchant power
generation facilities and engages in commodity sales and services related to
natural gas and electric power. DENA conducts business throughout the U.S. and
Canada through Duke Energy North America, LLC and Duke Energy Trading and
Marketing, LLC (DETM). DETM is approximately 40% owned by ExxonMobil Corporation
and approximately 60% owned by the Company. On April 11, 2003, the Company
announced that it will discontinue proprietary trading at DENA.
International Energy develops, operates and manages natural gas transportation
and power generation facilities, and engages in sales and marketing of natural
gas and electric power outside the U.S. and Canada. It conducts operations
primarily through Duke Energy International, LLC and its activities target power
generation in Latin America, power generation and natural gas transmission in
Asia-Pacific, and natural gas marketing in Northwest Europe.
Beginning in 2003, the business segments formally known as Other Energy Services
and Duke Ventures were combined and have been presented as Other Operations.
Other Operations is composed of diverse businesses, operating through Crescent
Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet), Duke Capital
Partners, LLC (DCP), Duke/Fluor Daniel (D/FD) and Energy Delivery Services
(EDS). Crescent develops high-quality commercial, residential and multi-family
real estate projects and manages land holdings primarily in the Southeastern and
Southwestern U.S. DukeNet develops and manages fiber optic communications
systems for wireless, local and long-distance communications companies; and for
selected educational, governmental, financial and health care entities. DCP, a
wholly owned merchant finance company, provides debt and equity capital and
financial advisory services primarily to the energy industry. In March 2003, the
Company announced that it will exit the merchant finance business at DCP in an
orderly manner. D/FD provides comprehensive engineering, procurement,
construction, commissioning and operating plant services for fossil-fueled
electric power generating facilities worldwide. D/FD is a 50/50 partnership
between the Company and Fluor Enterprises, Inc., a
6
wholly owned subsidiary of Fluor Corporation. EDS is an engineering,
construction, maintenance and technical services firm specializing in electric
transmission and distribution lines and substation projects.
2. Summary of Significant Accounting Policies
Restatement. As previously disclosed, in the third quarter of 2002, the Company
adopted the preliminary conclusions of Emerging Issues Task Force (EITF) Issue
No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and for Contracts Involved in Energy Trading and Risk
Management Activities." As a result, the Company began presenting the gains and
losses from its energy trading activities on a net basis as Trading and
Marketing Net Margin on its Consolidated Statements of Income in its Form 10-Q
for the quarter ended September 30, 2002. In Note 17 to the Company's 2002
Consolidated Financial Statements, operating revenues for each of the quarterly
periods during the year ended December 31, 2002 were reported as if the change
in presentation required by EITF Issue No. 02-03 had been in effect as of the
beginning of each period presented.
In connection with the preparation of the consolidated March 31, 2003 financial
statements and Form 10-Q, the Company determined that its operating revenues and
operating expenses for the three months ending March 31, 2002 were overstated by
approximately $800 million. As a result, the accompanying consolidated income
statement for the three month period ending March 31, 2002 has been restated
from the amounts previously reported. This adjustment has no impact on the
Company's operating income, net income or cash flows for that period.
The following table shows how the first quarter 2002 income statement has been
restated.
- -------------------------------------------------------------------------------------------------------------
Restatement of March 31, 2002 Operating Revenue (in millions)
- -------------------------------------------------------------------------------------------------------------
As Previously Reported
in Note 17 of the
Company's 2002 Reclassification of
Consolidated Financial Gain on Sale of Restatement
Statements Equity Investment Adjustment As Restated
-----------------------------------------------------------------------------------
Operating Revenue $3,023 $(14) $(801) $2,208
- -------------------------------------------------------------------------------------------------------------
The Company expects to file an amended December 31, 2002 Form 10-K as soon as
practicable. The Company expects the impacts of the restatement to result in a
reduction in operating revenues and operating expenses of approximately $600
million for 2002, $900 million for 2001 and $800 million for 2000. These
adjustments have no impact on the Company's operating income, net income or cash
flows for the respective periods.
These adjustments have no impact on Duke Energy's reported financials.
Consolidation. The Consolidated Financial Statements include the accounts of the
Company and all majority-owned subsidiaries, after eliminating significant
intercompany transactions and balances. These Consolidated Financial Statements
reflect all normal recurring adjustments that are, in the opinion of management,
necessary to present fairly the financial position and results of operations for
the respective periods. Amounts reported in the interim Consolidated Statements
of Income are not necessarily indicative of amounts expected for the respective
annual periods due to the effects of seasonal temperature variations on energy
consumption, the timing of maintenance on electric generating units and other
factors.
Conformity with generally accepted accounting principles (GAAP) requires
management to make estimates and assumptions that affect the amounts reported in
the financial statements and notes. Although these estimates are based on
management's best available knowledge of current and expected future events,
actual results could be different from those estimates.
7
Inventory. Inventory, except inventory held for trading, consists primarily of
materials and supplies, natural gas and natural gas liquid products held in
storage for transmission, processing and sales commitments. This inventory is
recorded at the lower of cost or market value, primarily using the average cost
method. The following table shows the components of inventory.
- --------------------------------------------------------------------------------
Inventory (in millions)
- --------------------------------------------------------------------------------
March 31, December 31,
2003 2002
----------------------------
Materials and supplies $ 382 $ 498
Petroleum products 56 83
Gas stored underground 43 71
Gas used in operations 13 14
----------------------------
Total inventory $ 494 $ 666
- --------------------------------------------------------------------------------
Accounting for Risk Management 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. Prior to the implementation of the
remaining provisions of EITF Issue No. 02-03 on January 1, 2003, certain
non-derivative energy trading contracts were also recorded on the Consolidated
Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on
Mark-to-Market and Hedging Transactions. See the Cumulative Effect of Changes in
Accounting Principles section below for further discussion of the implementation
of the provisions of Issue No. 02-03.
Effective January 1, 2003, in connection with the implementation of the
remaining provisions of Issue No. 02-03, the Company designates each energy
commodity derivative as either trading or non-trading. Certain non-trading
derivatives are further designated as either a hedge of a forecasted transaction
or future cash flows (cash flow hedge), a hedge of a recognized asset, liability
or firm commitment (fair value hedge), or a normal purchase or sale contract,
while certain non-trading derivatives remain undesignated. Derivatives related
to marketing and other risk management activities are designated as non-trading.
Derivatives designated as trading primarily relate to the Company's proprietary
trading activities. As discussed above the Company has announced it is
discontinuing proprietary trading at DENA (See Note 1).
The Company accounts for both trading and undesignated non-trading derivatives
using the mark-to-market accounting method and uses the accrual method for its
other derivatives. EITF Issue No. 02-03 requires realized and unrealized gains
and losses on all derivative instruments designated as trading to be shown on a
net basis in the income statement, but does not provide guidance on the income
statement presentation of gains and losses on undesignated non-trading
derivatives. EITF Issue No. 02-L, "Reporting Gains and Losses on Derivative
Instruments That Are Subject to FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities, and Not Held for Trading
Purposes," is currently an open issue for the EITF and any consensus reached on
this issue may require changes in the Company's presentation of non-trading
gains and losses. Gains and losses on non-derivative energy trading contracts
are presented on a gross or net basis in connection with the guidance in Issue
No. 99-19, "Reporting Revenue Gross as a Principal vs. Net as an Agent."
For each of the non-trading derivative categories identified above, the Company
reports gains and losses in the Consolidated Statements of Income as follows:
.. Gains and losses relating to non-trading derivatives designated as cash
flow or fair value hedges are reported on a gross basis, upon settlement,
in the same income statement category as the related hedged item.
.. Gains and losses relating to normal purchase or sale contracts are reported
on a gross basis upon settlement.
8
.. Gains and losses from undesignated non-trading physical derivatives that
are entered into and settled during the same month, which primarily relate
to the Company's natural gas wholesale marketing operations, are reported
on a gross basis.
.. Gains and losses from all other undesignated non-trading derivatives are
reported on a net basis in Trading and Marketing Net Margin.
Prior to January 1, 2003, unrealized and realized gains and losses on all energy
trading contracts, as defined in Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities", which included many
derivative and non-derivative instruments, were presented on a net basis in
Trading and Marketing Net Margin in the Consolidated Statements of Income. While
the income statement presentation of gains and losses for each category of
non-trading derivatives, as described above, remained consistent from 2002 to
2003, the definition of a trading and non-trading instrument changed from Issue
No. 98-10 to Issue No. 02-03. Under EITF Issue No. 98-10, all energy derivative
and non-derivative contracts were considered to be trading that were entered
into by an entity's energy trading operations, while under EITF Issue No. 02-03
an assessment is performed for each contract and only those individual
derivative contracts that are entered into with the intent of generating profits
on short-term differences in price are considered to be trading. As a result, a
significant number of derivatives previously classified as trading under EITF
Issue No. 98-10 became classified as non-trading as of January 1, 2003.
Other Current Liabilities. Through master collateral agreements, counterparties
must post cash collateral to the Company and its affiliates for exposure in
excess of a contractual threshold. The receipt of cash by the Company creates a
current liability on the Consolidated Balance Sheets for the amount received.
The amount of this current liability was approximately $650 million as of March
31, 2003 and approximately $355 million as of December 31, 2002 and is included
in Other Current Liabilities on the Consolidated Balance Sheets.
Goodwill. The following table shows the changes in the carrying amount of
goodwill for the three months ended March 31, 2003.
- -----------------------------------------------------------------------------------------------------------
Goodwill (in millions)
- -----------------------------------------------------------------------------------------------------------
Balance Acquired Balance
December 31, 2002 Goodwill Other /a/ March 31, 2003
-------------------------------------------------------------------------
Natural Gas Transmission $ 2,760 $ - $ (20) $2,740
Field Services 481 - 4 485
Duke Energy North America 100 - - 100
International Energy 246 - (1) 245
Other Operations 6 - - 6
Other 154 - - 154
--------------------------------------------------------------------------
Total consolidated $ 3,747 $ - $ (17) $3,730
- -----------------------------------------------------------------------------------------------------------
/a/ Amounts consist primarily of foreign currency adjustments and purchase price
adjustments to prior year acquisitions.
Guarantees. The Company accounts for guarantees and related contracts, for which
it is the guarantor, under Financial Accounting Standards Board (FASB)
Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others." In accordance with FIN 45, upon issuance or modification of a guarantee
on or after January 1, 2003, the Company recognizes a liability at the estimated
fair value of the obligation it assumes under that guarantee. The Company
relieves the obligation over the term of the guarantee or related contract in a
systematic and rational method. Any additional contingent loss for guarantee
contracts is accounted for and recognized in accordance with SFAS No. 5,
"Accounting for Contingencies."
9
Accumulated Other Comprehensive (Loss) Income. The following table shows the
components of and changes in accumulated other comprehensive income (loss).
- --------------------------------------------------------------------------------------------------------------
Accumulated Other Comprehensive (Loss) Income (in millions)
- --------------------------------------------------------------------------------------------------------------
Net Accumulated
Foreign Unrealized Minimum Pension Other
Currency Gains on Cash Liability Comprehensive
Adjustments Flow Hedges Adjustment Loss
------------------------------------------------------------------
Balance as of December 31, 2002 $(653) $455 $(14) $(212)
Other comprehensive income changes
during the quarter (net of taxes of
$57) 164 122 - 286
------------------------------------------------------------------
Balance as of March 31, 2003 $(489) $577 $(14) $ 74
------------------------------------------------------------------
Cumulative Effect of Change in Accounting Principles. As of January 1, 2003, the
Company adopted the remaining provisions of EITF Issue No. 02-03 and SFAS No.
143, "Accounting for Asset Retirement Obligations.". In accordance with the
transition guidance for these standards, the Company recorded a net-of-tax and
minority interest cumulative effect adjustment for change in accounting
principles of $52 million as a reduction in earnings. See additional discussion
of the cumulative effect adjustment below.
In October 2002, the EITF reached a final consensus on EITF Issue No. 02-03.
Primarily, the final consensus provided for (1) the rescission of the consensus
reached on EITF Issue No. 98-10, (2) the reporting of gains and losses on all
derivative instruments considered to be held for trading purposes to be shown on
a net basis in the income statement, and (3) gains and losses on non-derivative
energy trading contracts to be similarly presented on a gross or net basis, in
connection with the guidance in Issue No. 99-19.
As a result of the consensus on EITF Issue No. 02-03, all non-derivative energy
trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that
existed on October 25, 2002 and inventories that were recorded at fair values
have been adjusted to historical cost via a cumulative effect adjustment of $42
million (net of tax and minority interest) that reduced first quarter 2003
earnings. Adopting the final consensus on EITF Issue No. 02-03 did not require a
change to prior periods and, therefore, the Company did not change the 2002
classification of operating revenue and operating expense amounts.
In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. The standard applies
to legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal use of the
asset. For obligations related to non-regulated operations, a cumulative effect
adjustment of $10 million (net of tax and minority interest) was recorded in the
first quarter of 2003, as a reduction in earnings. (For a full discussion of
asset retirement obligations, see Note 6.)
New Accounting Standards. SFAS No. 146, "Accounting for Costs Associated with
Exit or Disposal Activities." In June 2002, the FASB issued SFAS No. 146 which
addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The
Company has adopted the provisions of SFAS No. 146 for restructuring activities
initiated after December 31, 2002. SFAS No. 146 requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost
was recognized on the date of the Company's commitment to an exit plan. SFAS No.
146 also establishes that the liability should initially be measured and
recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of
recognizing future restructuring costs as well as the amounts recognized.
10
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." In April 2003, the FASB issued SFAS No. 149, which amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. SFAS No. 149 clarifies the discussion around initial net investment and
when a derivative contains a financing component, and amends the definition of
the term underlying to conform it to language used in FIN 45. In addition, SFAS
No. 149 also incorporates certain Derivative Implementation Group Implementation
Issues. The provisions of SFAS No. 149 are effective for contracts entered into
or modified after June 30, 2003, and for hedging relationships designated after
June 30, 2003. The guidance should be applied to hedging relationships on a
prospective basis. The Company is currently assessing the impact SFAS No. 149
will have on its consolidated results of operations, cash flows and financial
position.
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities." In January 2003, the FASB issued FIN 46 which requires the primary
beneficiary of a variable interest entity's activities to consolidate the
variable interest entity. The primary beneficiary is the party that absorbs a
majority of the expected losses and/or receives a majority of the expected
residual returns of the variable interest entity's activities. FIN 46 is
immediately applicable to variable interest entities created, or interests in
variable interest entities obtained, after January 31, 2003. For variable
interest entities created, or interests in variable interest entities obtained,
on or before January 31, 2003, FIN 46 is required to be applied in the first
fiscal year or interim period beginning after June 15, 2003. FIN 46 may be
applied prospectively with a cumulative-effect adjustment as of the date it is
first applied, or by restating previously issued financial statements with a
cumulative-effect adjustment as of the beginning of the first year restated. FIN
46 also requires certain disclosures of an entity's relationship with variable
interest entities. The Company has not identified any variable interest entities
created, or interests in variable entities obtained, after January 31, 2003 and
continues to assess the existence of any interests in variable interest entities
created on or prior to January 31, 2003. It is reasonably possible that the
Company will disclose information about a variable interest entity upon the
application of FIN 46, primarily as the result of investments it has in certain
unconsolidated affiliates. Any significant exposure to losses related to these
entities would be related to guarantee obligations as discussed in Note 9. The
Company continues to assess FIN 46 but does not anticipate that it will have a
material impact on its consolidated results of operations, cash flows or
financial position.
Reclassifications. Certain prior period amounts have been reclassified to
conform to current classifications.
3. Business Acquisitions
The Company consolidates assets and liabilities from acquisitions as of the
purchase date, and includes earnings from acquisitions in consolidated earnings
after the purchase date. Assets acquired and liabilities assumed are recorded at
estimated fair values on the date of acquisition. The purchase price minus the
estimated fair value of the acquired assets and liabilities is recorded as
goodwill. The allocation of the purchase price may be adjusted if additional
information on asset and liability valuations becomes available within one year
after the acquisition.
On March 14, 2002, the Company acquired Westcoast Energy Inc (Westcoast) for
approximately $8 billion, including the assumption of $4.7 billion of debt. The
Westcoast acquisition was accounted for using the purchase method, and goodwill
of approximately $2.3 billion was recorded in the transaction, of which
approximately $57 million is expected to be deductible for income tax purposes.
Of the $57 million, $52 million was allocated for tax purposes to Empire State
Pipeline which was sold in February 2003.
During the first quarter of 2003, the Company recorded additional purchase price
adjustments as information regarding the assets acquired became available,
including adjustments related to the sale of Empire State Pipeline to National
Fuel Gas Company. The purchase price amounts in the following table reflect the
additional purchase price adjustments and the adjustments for the sale of Empire
State Pipeline.
11
The following table summarizes the estimated fair values of the assets acquired
and liabilities assumed as of the acquisition date.
- -----------------------------------------------------------------
Purchase Price Allocation for Westcoast Acquisition (in millions)
- -----------------------------------------------------------------
Current assets $ 2,050
Investments and other assets 1,207
Goodwill 2,253
Property, plant and equipment 4,991
Regulatory assets and deferred debits 809
-------
Total assets acquired 11,310
-------
Current liabilities 1,655
Long-term debt 4,132
Deferred credits and other liabilities 1,662
Minority interests 560
-------
Total liabilities assumed 8,009
-------
Net assets acquired $ 3,301
- -----------------------------------------------------------------
Operating revenues would have been $2,526 million and net income would have been
$211 million as of the period ended March 31, 2002 if the Westcoast acquisition
had taken place at the beginning of the period ended March 31, 2002.
4. Business Segments
The Company's reportable segments offer different products and services and are
managed separately as business units. Accounting policies for the Company's
segments are the same as those described in Note 2. Management evaluates segment
performance primarily based on earnings before interest and taxes (EBIT) after
deducting minority interests. The following table shows how consolidated EBIT is
calculated before deducting minority interests.
- ------------------------------------------------------------------------
Reconciliation of Operating Income to EBIT (in millions)
- ------------------------------------------------------------------------
Three Months Ended
March 31,
--------------------------
2003 2002
--------------------------
Operating income $558 $339
Other income and expenses 71 79
--------------------------
EBIT $629 $418
- ------------------------------------------------------------------------
EBIT may be viewed as a non-GAAP measure under the rules of the Securities and
Exchange Commission (SEC). The Company has included EBIT in its disclosures
because it is the primary performance measure used by management to evaluate
total company and segment performance. On a segment basis, it includes all
profits (both operating and non-operating) before deducting interest and taxes,
and is net of the minority interest expense related to those profits. Management
believes EBIT is a good indicator of each segment's operating performance, as it
represents the results of the Company's ownership interests in operations
without regard to financing methods or capital structure. As an indicator of the
Company's operating performance, EBIT should not be considered an alternative
to, or more meaningful than, net income or cash flow as determined in accordance
with GAAP. The Company's EBIT may not be comparable to a similarly titled
measure of another company because other entities may not calculate EBIT in the
same manner.
Cash and cash equivalents are managed centrally by the Company. Since the
business units do not manage these items, the gains and losses on foreign
currency remeasurement associated with such cash balances and third party
interest income on these balances are excluded from the segments' EBIT.
12
In the accompanying table, EBIT includes the profit on intersegment sales at
prices management believes are representative of arms' length transactions. The
line item "Other" primarily includes certain unallocated corporate costs.
- ---------------------------------------------------------------------------------------------------------
Business Segment Data (in millions)
- ---------------------------------------------------------------------------------------------------------
Capital
Depreciation and
Unaffiliated Intersegment Total and Investment
Revenues Revenues Revenues EBIT Amortization Expenditures
--------------------------------------------------------------------------
Three Months Ended
March 31, 2003
Natural Gas Transmission $ 879 $ 89 $ 968 $423 $ 96 $ 198
Field Services 1,968 504 2,472 33 78 31
Duke Energy North America 1,133 88 1,221 21 58 160
International Energy 382 - 382 54 25 25
Other Operations 80 1 81 20 7 61
Other 1 2 3 34 3 44
Eliminations and
minority interests - (684) (684) 46 - -
Third party interest income - - - 3 - -
Foreign currency loss - - - (5) - -
-------------------------------------------------------------------------
Total consolidated $ 4,443 $ - $ 4,443 $629 $ 267 $ 519
-------------------------------------------------------------------------
Three Months Ended
March 31, 2002
Natural Gas Transmission $ 422 $ 28 $ 450 $266 $ 54 $ 2,020
Field Services 932 202 1,134 35 74 110
Duke Energy North America 437 (181) 256 46 29 736
International Energy 288 1 289 57 23 81
Other Operations 129 34 163 4 5 126
Other - (4) (4) (49) 3 36
Eliminations and
minority interests - (80) (80) 14 - -
Third party interest income - - - 36 - -
Foreign currency gain - - - 9 - -
Cash acquired in acquisitions - - - - - (77)
-------------------------------------------------------------------------
Total consolidated $ 2,208 $ - $ 2,208 $418 $ 188 $ 3,032
=========================================================================
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,
2003 2002
---------------------------
Natural Gas Transmission $16,049 $15,168
Field Services 7,705 6,992
Duke Energy North America 17,683 16,272
International Energy 5,779 5,804
Other Operations 2,123 2,316
Other, net of eliminations (240) 1,013
---------------------------
Total consolidated $49,099 $47,565
===========================
13
5. Regulatory Matters
Regulatory Assets and Liabilities. In the first quarter of 2003, the Company
adopted SFAS No. 143, which applies to legal obligations associated with the
retirement of tangible long-lived assets and the related asset retirement costs
(see Note 6). Certain of the Company's regulated operations recognize some
removal costs as a component of accumulated depreciation for property that does
not have an associated legal retirement obligation, in accordance with
regulatory treatment. As of March 31, 2003, the amount of accumulated
depreciation on the Consolidated Balance Sheet related to this regulatory
liability is approximately $15 million.
6. Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. The standard applies
to legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal use of the
asset. Asset retirement obligations at the Company relate primarily to the
retirement of certain gathering pipelines and processing facilities, the
retirement of some gas-fired power plants, obligations related to right-of-way
agreements and contractual leases for land use.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability increases due to the
passage of time based on the time value of money until the obligation is
settled.
In accordance with SFAS No. 143, the Company identified certain assets that have
an indeterminate life, and thus a future retirement obligation is not
determinable. These assets included on-shore and some off-shore pipelines,
certain processing plants and distribution facilities and some gas-fired power
plants. A liability for these asset retirement obligations will be recorded when
a fair value is determinable.
Certain of the Company's regulated operations recognize some removal costs as a
component of depreciation in accordance with regulatory treatment. While these
amounts will remain in accumulated depreciation, to the extent they do not
represent SFAS No. 143 legal retirement obligations, they are disclosed as part
of the regulatory matters footnote (see Note 5).
SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and
was adopted by the Company on January 1, 2003. As of January 1, 2003, the
implementation of SFAS No. 143 resulted in a net increase in total assets of $43
million, consisting primarily of an increase in net property, plant and
equipment. Liabilities increased by $53 million, primarily representing the
establishment of an asset retirement obligation liability of $69 million,
reduced by the amount that was already recorded for cost of removal. For
obligations related to non-regulated operations, a net-of-tax cumulative effect
of a change in accounting principle adjustment of $10 million was recorded in
the first quarter of 2003 as a reduction in earnings.
The following table shows the asset retirement obligation liability as though
SFAS No. 143 had been in effect for the three prior years.
- -----------------------------------------------------------------------
Pro forma Asset Retirement Obligation Liability (in millions)
- -----------------------------------------------------------------------
January 1, 2000 $19
December 31, 2000 37
December 31, 2001 46
December 31, 2002 69
- -----------------------------------------------------------------------
14
The pro-forma net income effect of adopting SFAS No. 143 is not shown due to
its immaterial impact.
The asset retirement obligation is adjusted each quarter for any liabilities
incurred or settled during the period, accretion expense and any revisions made
to the estimated cash flows. The following table shows the reconciliation of the
asset retirement obligation liability for the quarter ended March 31, 2003.
- --------------------------------------------------------------------------------
Reconciliation of Asset Retirement Obligation Liability for the Quarter Ended
March 31, 2003 (in millions)
- --------------------------------------------------------------------------------
Balance as of January 1, 2003 $69
Accretion expense 2
Other 1
----------------
Balance as of March 31, 2003 $72
- --------------------------------------------------------------------------------
7. Debt and Credit Facilities
In the first quarter of 2003, $500 million of the Company's commercial paper
that had been included in Long-term Debt on the December 31, 2002 Consolidated
Balance Sheet was reclassified on the March 31, 2003 Consolidated Balance Sheet
to Notes Payable and Commercial Paper. This reclassification reflects from the
Company's intention to no longer maintain an outstanding long-term portion of
commercial paper.
In March 2003, DEFS entered into a $100 million funded short-term loan with Bank
One, NA. This short-term loan matures in September 2003, and may be prepaid at
any time. This short-term loan has an interest rate equal to, at DEFS' option,
either (1) the London Interbank Offered Rate plus 1.35% per year or (2) the
higher of (a) the Bank One, NA prime rate and (b) the Federal Funds rate plus
0.50% per year. DEFS does not plan to refinance this short-term loan when it
matures.
Also in March 2003, DEFS closed a 364-day syndicated bank credit facility for
$350 million to replace an expiring syndicated bank credit facility.
In March 2003, a wholly owned subsidiary of the Company, Duke Australia Finance
Pty Ltd. closed a syndicated bank credit facility for 315 million Australian
dollars (U.S. $190 million) to replace a syndicated bank credit facility that
expired.
The following table summarizes the Company's credit facilities and related
amounts outstanding as of March 31, 2003. The majority of the credit facilities
support commercial paper programs. The issuance of commercial paper, letters of
credit and other borrowings reduces the amount available under the credit
facilities.
15
- --------------------------------------------------------------------------------
Credit Facilities Summary as of March 31, 2003 (in millions)
- --------------------------------------------------------------------------------
Credit Amounts Outstanding
-------------------------------------------------
Expiration Facilities Commercial Letters of Other
Date Available Paper Credit Borrowings Total
---------------------------------------------------------------------------
Duke Capital Corporation
- ------------------------
$500 Temporary bilateral/b, c/ June 2003
$700 364-Day syndicated/a, b, c/ August 2003
$500 364-Day syndicated letter of credit/a,
b, c, d/ April 2003
$142 364-Day bilateral/a, b, c/ August 2003
$550 Multi-year syndicated/a, b, c/ August 2004
$538 Multi-year syndicated letter of credit
/b, c/ April 2004
Total Duke Capital Corporation $2,930 $679 $517 - $1,196
Westcoast Energy Inc.
- ---------------------
$171 364-Day syndicated/a, b/ December 2003
$136 Two-year syndicated/b/ December 2004
Total Westcoast Energy Inc./e/ 307 23 - - 23
Union Gas Limited
- -----------------
$409 364-Day syndicated/f/ July 2003 409 - - - -
Duke Energy Field Services, LLC
- -------------------------------
$350 364-Day syndicated/a, c, g/ March 2004 350 84 - - 84
Duke Australia Finance Pty Ltd.
- -------------------------------
$190 364-Day syndicated/h/ March 2004 190 - - - -
-
Duke Australia Pipeline Finance Pty Ltd.
- ----------------------------------------
$188 Multi-year syndicated/i/ February 2005 188 134 - 209 343
------------------------------------------------------------
Total $4,374 $920 $517 $209 $1,646
- --------------------------------------------------------------------------------------------------------------------------
/a/ Credit facility contains an option allowing borrowing up to the full amount
of the facility on the day of initial expiration for up to one year.
/b/ Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 65%.
/c/ Credit facility contains an interest coverage covenant of two and a half
times or greater.
/d/ In April 2003, credit facility matured and was replaced with a $253 million
364-day syndicated letter of credit facility with an April 2004 expiration.
/e/ Credit facilities are denominated in Canadian dollars, and totaled 450
million Canadian dollars as of March 31, 2003.
/f/ Credit facility contains an option allowing up to 50% of the amount of the
facility to be borrowed on the day of initial expiration for up to one
year. Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 75%. Credit facility is denominated in
Canadian dollars, and was 600 million Canadian dollars as of March 31,
2003.
/g/ Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 53%.
/h/ Credit facility is guaranteed by the Company. Credit facility is
denominated in Australian dollars, and was 315 million Australian dollars
as of March 31, 2003.
/i/ Credit facility is guaranteed by the Company. Credit facility is
denominated in Australian dollars, and totaled 312 million Australian
dollars as of March 31, 2003. Duke Australia Pipeline Finance Pty Ltd. is a
wholly owned subsidiary of Duke Energy.
In addition to the existing bank credit facilities, the Company has a separate
option to borrow up to $250 million between June 30, 2003 and August 29, 2003.
Any amounts borrowed under this option would be due no later than March 31,
2004. Also, the Company is currently maintaining a minimum cash position of $500
million to be used for short-term liquidity needs. This cash position is
invested in highly rated, liquid, short-term money market securities.
As of March 31, 2003, the Company has approximately $2,400 million of credit
facilities which mature in 2003. It is the Company's intent to significantly
reduce its need for these facilities as the year progresses and thus resyndicate
less than the total $2,400 million.
16
The Company's credit agreements contain various financial and other covenants.
Failure to meet those covenants beyond applicable grace periods could result in
acceleration of due dates of certain borrowings and/or termination of the
agreements. As of March 31, 2003, the Company was in compliance with those
covenants. In addition, certain of the agreements contain cross-acceleration
provisions that may allow acceleration of payments or termination of the
agreements upon nonpayment or acceleration of other significant indebtedness of
the applicable borrower or certain of its subsidiaries.
As of March 31, 2003, the Company and its subsidiaries had effective SEC shelf
registrations for up to $1,000 million in gross proceeds from debt and other
securities. As of March 31, 2003, the Company also had access to 950 million
Canadian dollars (U.S. $648 million) available under Canadian shelf
registrations for issuances in the Canadian market.
8. Commitments and Contingencies
Litigation
Western Power Disputes. Several investigations and regulatory proceedings at the
state and federal levels are looking into the causes of high wholesale
electricity prices in the western U.S. during 2000 and 2001. As a result, the
FERC has ordered some sellers, including DETM, to refund, or to offset against
outstanding accounts receivable, amounts billed for electricity sales in excess
of a FERC-established proxy price. In December 2002, the presiding
administrative law judge in the FERC refund proceedings issued his proposed
findings with respect to the mitigated market clearing price, including his
preliminary determinations of the refund liability of each seller of electricity
in the California Independent System Operator (CAISO) and the California Power
Exchange (CalPX). These proposed findings estimated that DETM has refund
liability of approximately $95 million in the aggregate to both the CAISO and
CalPX. This would be offset against the remaining receivables still owed to DETM
by the CAISO and CalPX. The proposed findings were the presiding judge's
estimates only, and are subject to further recalculation and adoption by the
FERC in connection with its ongoing wholesale pricing investigation. (see Note
13 to the Consolidated Financial Statements, "Commitments and Contingencies -
Litigation, Western Power Disputes, Other Proceedings," in the Company's Form
10-K for December 31, 2002 for additional information on these matters.) On
March 3, 2003, various parties (including the California attorney general) filed
at the FERC seeking modification of the FERC's refund orders and alleging that
DETM and others manipulated wholesale electricity prices in periods prior to the
initial refund period. DETM filed responses denying the California parties'
allegations.
On March 26, 2003, the FERC issued staff recommendations relating to the FERC's
investigation into the causes of high wholesale electricity prices in the
Western U.S. during 2000 and 2001, and an order in the FERC's refund proceeding.
The recommendations and order address, among other things: modifying the
presiding judge's refund findings with respect to the gas price component and
certain other components of the refund calculation; issuance of show cause
orders related to certain energy trading practices; requiring trading entities
to demonstrate that they have corrected their internal processes for reporting
trading data to the Trade Press in order to continue selling natural gas at
wholesale (see "Trading Matters" below); and establishing a ban on prearranged
"round trip" trades as a condition of blanket certificates (see Note 13 to the
Consolidated Financial Statements, "Commitments and Contingencies - Litigation,
Trading Matters," in the Company's Form 10-K for December 31, 2002 for
additional information on "round-trip" trading). On April 30, 2003, the FERC
issued an order consistent with the FERC staff's March 26, 2003 recommendations
directing Duke Energy and ten other companies to submit by June 16, 2003 written
demonstrations regarding gas price reporting practices. Duke Energy continues to
evaluate the staff recommendations and refund order to analyze the impact they
might have on Duke Energy.
17
Related Litigation. In December 2002, plaintiffs filed class-action suits
against Duke Energy and numerous other energy companies in state court in
Oregon and in federal court in Washington state making allegations similar to
those in the California suits. Plaintiffs allege they paid unreasonably high
prices for electricity and/or natural gas during the time period from January
2000 to the present as a result of defendants' activities which were fraudulent,
negligent and in violation of each state's business practices laws. Plaintiffs
have sought to dismiss these two suits, and in April 2003 a new class action
lawsuit was filed against Duke Energy and numerous other energy companies in
state court in San Diego, California on behalf of purchasers of electric and/or
natural gas energy residing in the states of Oregon, Washington, Utah, Nevada,
Idaho, New Mexico, Arizona, and Montana. Plaintiffs claim that wholesale and
retail pricing throughout the "West Coast Energy Market" is dominated by trading
and pricing in California and allege that defendants, acting unilaterally and in
concert with other energy companies, engaged in manipulation of the supply of
energy into the California markets, resulting in artificially high electricity
prices. Plaintiffs, also alleging that defendants' actions were in violation of
California's antitrust and unfair business practices laws, seek actual and
treble damages; restitution of funds acquired by unfair or unlawful means; an
injunction prohibiting the defendants from engaging in the alleged unlawful
activity; and other appropriate relief.
Trading Matters. In October 2002, the FERC issued a data request to the "Largest
North American Gas Marketers, As Measured by 2001 Physical Sales Volumes
(Bcf/d)," including DETM. In general, the data request asks for information
concerning natural gas price data submitted by the gas marketers to publishers
of natural gas price indices. DETM responded to the FERC's data request and is
also responding to requests by the Commodities Future Trading Commission (CFTC)
for similar information. The March 26, 2003 FERC staff recommendations (see
"Western Power Disputes" above) included a report on the FERC's investigation
regarding information provided to publications. The report noted that the
practice in the Company's Salt Lake City office was to report actual
transactions while the practice in the Houston office was to report a sense of
the market while sometimes taking the Company's open positions into account. The
FERC staff report also identified controls that should be implemented to address
inaccurate reporting of information to trade publications. The Company has
implemented the controls identified in the report. Management is unable to
predict what, if any, action the FERC and the CFTC will take with respect to
these matters.
Sonatrach/ Citrus Trading Corporation (Citrus). In a matter related to the
Sonatrach arbitration (see Note 13 to the Consolidated Financial Statements,
"Commitments and Contingencies - Litigation, Sonatrach," in the Company's Form
10-K for December 31, 2002), Citrus filed suit in March 2003 against Duke Energy
LNG Sales, Inc. (Duke LNG) in the District Court of Harris County, Texas. The
suit alleged that Duke LNG breached the parties' natural gas purchase contract
(the Citrus Agreement) by failing to provide sufficient volumes of gas to
Citrus. Duke LNG contends that as a result of Sonatrach's actions, Duke LNG
experienced a loss of liquefied natural gas (LNG) supply that affects Duke LNG's
obligations and termination rights under the Citrus Agreement. The Citrus
petition seeks unspecified damages and a judicial determination that contrary to
Duke LNG's position, Duke LNG has not experienced a loss of LNG supply. Duke LNG
subsequently terminated the Citrus contract and filed a counterclaim in the
Texas action asserting that Citrus breached the terms of the Citrus Agreement
by, among other things, failing to provide sufficient security for the gas
transactions. Citrus has denied that Duke LNG has the right to terminate the
agreement. The Company continues to evaluate the claims at issue in this matter
and intends to vigorously defend itself.
Enron Bankruptcy. In December 2001, Enron filed for relief pursuant to Chapter
11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the
Southern District of New York. Additional affiliates have filed for bankruptcy
since that date. Certain affiliates of Duke Energy engaged in transactions with
various Enron entities prior to the bankruptcy filings. DETM was a member of the
Official Committee of Unsecured Creditors in the bankruptcy cases which are
being jointly administered, but as of February 2003, DETM resigned from the
Official Committee of Unsecured Creditors in the Enron bankruptcy case. In 2001,
the Company recorded a reserve to offset its exposure to Enron.
18
In mid-November 2002, various Enron trading entities demanded payment from DETM
for certain energy commodity sales transactions without regard to the set-off
rights of DETM and demanded that DETM detail balances due under certain master
trading agreements without regard to the set-off rights of DETM. On December 13,
2002, DETM filed an adversary proceeding against Enron, seeking, among other
things, a declaration affirming each plaintiff's right to set off its respective
debts to Enron. The complaint alleges that the Enron affiliates were operated by
Enron as its alter-ego and as components of a single trading enterprise, and
that DETM should be permitted to exercise their respective rights of mutual
set-off against the Enron trading enterprise under the Bankruptcy Code. The
complaint also seeks the imposition of a constructive trust so that any claims
by Enron against DETM are subject to the respective set-off rights of DETM. On
April 17, 2003, DETM's adversary proceeding was dismissed by the bankruptcy
judge for lack of standing. On April 30, 2003, DETM filed their notice of appeal
of this decision.
Management believes that the final disposition of the Enron bankruptcy will have
no material adverse effect on consolidated results of operations, cash flows or
financial position.
Other Litigation and Legal Proceedings. The Company and its subsidiaries are
involved in other legal, tax and regulatory proceedings before various courts,
regulatory commissions and governmental agencies regarding performance,
contracts, royalty disputes, mismeasurement and mispayment claims (some of which
are brought as class actions), and other matters arising in the ordinary course
of business, some of which involve substantial amounts. Management believes that
the final disposition of these proceedings will have no material adverse effect
on consolidated results of operations, cash flows or financial position.
9. Guarantees and Indemnifications
The Company and certain of its subsidiaries have various financial and
performance guarantees and indemnifications which are issued in the normal
course of business. As discussed below, these contracts include performance
guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. The Company enters into these arrangements to facilitate a
commercial transaction with a third party by enhancing the value of the
transaction to the third party.
Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the
prime contractor to the U.S. Department of Energy (DOE) under a contract (the
Prime Contract) in which DCS will design, construct, operate and deactivate a
MOX fuel fabrication facility (MOX FFF). The domestic MOX fuel project was
prompted by an agreement between the U.S. and the Russian Federation to dispose
of their respective excess weapon-grade plutonium by fabricating MOX fuel and
irradiating such MOX fuel in commercial nuclear reactors. As of March 31, 2003,
the Company, through its indirect wholly owned subsidiary, Duke Project Services
Group, Inc. (DPSG), held a 40% ownership interest in DCS. Additionally, Duke
Power, an affiliate of the Company, has entered into a subcontract with DCS (the
Duke Power Subcontract) to prepare its McGuire and Catawba nuclear reactors (the
Nuclear Reactors) for use of the MOX fuel and to purchase MOX fuel produced at
the MOX FFF for use in the Nuclear Reactors.
As required under the Prime Contract, DPSG and the other owners of DCS have
issued a guarantee to the DOE (the DOE Guarantee) pursuant to which the owners
of DCS jointly and severally guarantee to the DOE all of DCS' payment and
performance obligations under the Prime Contract. The Prime Contract consists of
a "Base Contract" phase and three optional phases. The DOE has the right to
extend the term of the Prime Contract to cover the three optional phases on a
sequential basis, subject to DCS and DOE reaching agreement, through good-faith
negotiations on certain remaining open terms applying to each of the option
phases. Each of the three option phases will be negotiated separately, as the
time for exercising each option phase becomes due under the Prime Contract. If
the DOE does not exercise its right to extend the term of the Prime Contract to
cover any or all of the optional phases, DCS' performance obligations under the
Prime Contract will end upon completion of the then-current performance phase.
Under the Base Contract phase, which covers the design of the MOX FFF and design
modifications to the Nuclear Reactors, DCS is to receive cost reimbursement plus
a fixed fee. The first option phase includes construction and cold startup of
the MOX FFF and modification of the Nuclear Reactors, and provides for DCS to
receive cost
19
reimbursement plus an incentive fee. The second option phase
provides for taking the MOX FFF from cold to hot startup, operation of the MOX
FFF, and irradiation of the MOX fuel in the Nuclear Reactors. For the second
option phase, DCS is to receive a cost reimbursement plus an incentive fee
through hot startup and, thereafter, cost-sharing plus a fee. The third option
phase involves DCS's deactivation of the MOX FFF in exchange for a fixed price
payment. As of March 31, 2003, DCS' performance obligations under the Prime
Contract include only the Base Contract phase, since the DOE has not yet
exercised its option to extend the term of performance under the Prime Contract
to the first option phase, and DCS and the DOE have not yet agreed on all open
terms and conditions applicable to that phase.
Additionally, DPSG and the other owners of DCS have issued a guarantee to Duke
Power (the Duke Power Guarantee) under which the owners of DCS jointly and
severally guarantee to Duke Power all of DCS' payment and performance
obligations under the Duke Power Subcontract or any other agreement between DCS
and Duke Power implementing the Prime Contract. The Duke Power Subcontract
consists of a "Base Subcontract" phase and two optional phases. DCS has the
right to extend the term of the Duke Power Subcontract to cover the two option
phases on a sequential basis, subject to Duke Power and DCS reaching agreement,
through good-faith negotiations on certain remaining open terms applying to each
of the option phases. Under the Base Subcontract phase, Duke Power will perform
technical and regulatory work required to prepare the Nuclear Reactors to use
MOX fuel, and receive cost reimbursement plus a fixed fee. The first option
phase provides for modification to the Nuclear Reactors as well as additional
technical and regulatory work, and provides for Duke Power to receive cost
reimbursement plus a fee. The second option phase provides for Duke Power to
purchase from DCS MOX fuel produced at the MOX FFF for use in the Nuclear
Reactors, at discounts to prices of equivalent uranium fuel, over a 15-year
period starting upon completion of the first option phase. As of March 31, 2003,
DCS' performance obligations under the Duke Power Subcontract include only the
Base Subcontract phase, since DCS has not yet exercised its option to extend the
term of performance under the Duke Power Subcontract to the first option phase,
and DCS and Duke Power have not yet agreed on all open terms and conditions
applicable to that phase.
The cost reimbursement nature of DCS' commitment under the Prime Contract and
the Duke Power Subcontract limits the exposure of DCS. Credit risk to DCS is
limited in that the Prime Contract is with the DOE, a U.S. governmental entity.
DCS is under no obligation to perform any contract work under the Prime Contract
before funds have been appropriated from the U.S. Congress.
The Company is unable to estimate the maximum potential amount of future
payments DPSG could be required to make under the DOE Guarantee and the Duke
Power Guarantee due to the uncertainty of whether: the DOE will exercise its
options under the Prime Contract; the parties to the Prime Contract and the Duke
Power Subcontract, respectively, will reach agreement on the remaining open
terms for each option phase under the contracts; and the U.S. Congress will
authorize funding for DCS' work under the Prime Contract. Any liability of DPSG
under the DOE Guarantee or the Duke Power Guarantee is directly related to and
limited by the Prime Contract and the Duke Power Subcontract, respectively. DPSG
also has recourse to the other owners of DCS for any amounts paid under the DOE
Guarantee or the Duke Power Guarantee in excess of its proportional ownership
percentage of DCS.
As of March 31, 2003, the Company had no material liabilities recorded on its
Consolidated Balance Sheet for the above mentioned MOX guarantees.
Other Guarantees and Indemnifications. The Company has issued performance
guarantees to customers and other third parties that guarantee the payment and
performance of other parties, including certain non-wholly owned entities. The
maximum potential amount of future payments the Company could have been required
to make under these performance guarantees as of March 31, 2003 was
approximately $2.8 billion. Of this amount, approximately $2.1 billion relates
to guarantees of the payment and performance of affiliated entities, such as
Duke Energy Fuels and Duke Energy Merchants, LLC and approximately $275 million
relates to guarantees of the payment and performance of less than wholly-owned
consolidated entities. Approximately $175 million of the performance guarantees
expire in 2003, approximately $50 million expire in 2004, and approximately $25
million expire in 2005, with the remaining performance guarantees having no
contractual expiration. Additionally, the Company has issued joint and several
20
guarantees to certain of the D/FD project owners, which guarantee the
performance of D/FD under its engineering, procurement and construction
contracts and other contractual commitments. These guarantees have no
contractual expiration and no stated maximum amount of future payments that the
Company could be required to make. Additionally, Fluor Enterprises, Inc., as 50%
owner in D/FD, has issued similar joint and several guarantees to the same D/FD
project owners. In accordance with the D/FD partnership agreement, each of the
D/FD partners is responsible for 50% of any payments to be made under these
guarantee contracts.
Westcoast has issued performance guarantees to third parties guaranteeing the
performance of unconsolidated entities, such as equity method projects, and of
entities previously sold by Westcoast to third parties. These performance
guarantees require Westcoast to make payment to the guaranteed third party upon
the failure of the unconsolidated entity to make payment under certain of its
contractual obligations, such as debt, purchase contracts and leases. The
maximum potential amount of future payments Westcoast could have been required
to make under these performance guarantees as of March 31, 2003 was
approximately $150 million. Of these guarantees, approximately $25 million
expire from 2004 to 2007, with the remainder expiring after 2007 or having no
contractual expiration.
Stand-by letters of credit are conditional commitments issued by banks to
guarantee the performance of non-wholly owned entities to a third party or
customer. Under these agreements, the Company and Westcoast have payment
obligations which are triggered by the failure of a non-wholly owned entity to
make payment to a third party or customer, according to the terms of the
underlying contract and the subsequent draw by the third party or customer under
the letter of credit. These letters of credit expire in various amounts between
2003 and 2004. The maximum potential amount of future payments the Company and
Westcoast could have been required to make under these letters of credit as of
March 31, 2003 was approximately $425 million. Of this amount, approximately
$275 million relates to letters of credit issued on behalf of less than wholly
owned consolidated entities and approximately $75 million relates to letters of
credit issued on behalf of Duke Energy affiliated entities. Related to these
letters of credit, the Company has received collateral from non-wholly owned
entities in the amount of approximately $125 million as of March 31, 2003.
The Company has guaranteed the issuance of surety bonds, obligating itself to
make payment upon the failure of a non-wholly owned entity to honor its
obligations to a third party. As of March 31, 2003, the Company had guaranteed
approximately $125 million of outstanding surety bonds related to obligations of
non-wholly owned entities. These bonds expire in various amounts, primarily
between 2003 and 2004. Of this amount, approximately $10 million relates to
obligations of less than wholly owned consolidated entities and approximately
$20 million relates to obligations of Duke Energy affiliated entities.
Field Services and Natural Gas Transmission have issued certain guarantees of
debt associated with non-consolidated entities. In the event that the
non-consolidated entity defaults on the debt payments, Field Services and
Natural Gas Transmission would be required to perform under the guarantees and
make payment on the outstanding debt balance of the non-consolidated entity. As
of March 31, 2003, Field Services was the guarantor of approximately $100
million of debt associated with non-consolidated entities. Natural Gas
Transmission was the guarantor of approximately $10 million of debt associated
with non-consolidated entities (including $5 million related to Westcoast).
These guarantees principally expire in 2003 for Field Services and 2019 for
Natural Gas Transmission.
The Company has certain guarantees issued to customers or other third parties
related to the payment or performance obligations of certain entities that were
previously wholly owned but which have been sold to third parties, such as
DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc.
(DE&S). These guarantees are primarily related to payment of lease obligations,
debt obligations and performance guarantees related to goods and services
provided. In connection with the sale of DE&S, the Company has received
back-to-back indemnification from the buyer indemnifying the Company for any
amounts paid by the Company related to the DE&S guarantees. In connection with
the sale of DukeSolutions, the Company received indemnification from the buyer
for the first $2.5 million paid by the Company related to
21
the DukeSolutions guarantees. Additionally, for certain performance guarantees,
the Company has recourse to subcontractors involved in providing services to a
customer. These guarantees have various terms ranging from 2003 to 2019, with
others having no specific term. The Company is unable to estimate the total
maximum potential amount of future payments under these guarantees since most of
the underlying guaranteed agreements contain no limits on potential liability.
The Company has entered into various indemnification agreements related to
purchase and sale agreements and other types of contractual agreements with
vendors and other third parties. These indemnification agreements typically
cover environmental, tax, litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these agreements.
Typically, claims may be made by third parties under these indemnification
agreements for various periods of time depending on the nature of the claim. The
Company's maximum potential exposure under these indemnification agreements can
range from a specified dollar amount to an unlimited amount depending on the
nature of the claim and the particular transaction. The Company is unable to
estimate the total maximum potential amount of future payments under these
indemnification agreements due to several factors, including uncertainty as to
whether claims will be made under these indemnities.
As of March 31, 2003, the Company had recorded no material liabilities for the
guarantees and indemnifications mentioned above.
10. Subsequent Events
In April 2003, the Company closed on substantially all elements of a transaction
to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada
Marketing and Aux Sable natural gas liquids plant to Enbridge Inc. and Fort
Chicago Energy Partners L.P. for approximately $250 million. This sale resulted
in an immaterial net loss. The transaction was completed except for the
Company's small ownership interest related to the U.S. segment of Alliance
Pipeline, which is expected to close in October 2003 and represents
approximately $11 million in proceeds. Alliance Pipeline extends from Fort St.
John in British Columbia to Chicago, Illinois. The Aux Sable plant extracts
natural gas liquids at the outlet of the Alliance Pipeline in Chicago. The
Company obtained its minority ownership interest in the Alliance natural gas
pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant
through its acquisition of Westcoast in 2002.
In April 2003, the Company sold all its Class B units of TEPPCO Partners, L.P.
(TEPPCO) for approximately $114 million. The Company recorded a pre-tax gain of
approximately $11 million on the sale. TEPPCO is a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil.
In April and May 2003, DEFS entered into two separate purchase and sale
agreements by which it will sell one package of assets to Crosstex Energy
Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy,
LLC (ScissorTail) for a total sales price of approximately $91 million, plus or
minus various adjustments to be made at closing. The gain on the sale will be
approximately $17 million (at the Company's approximately 70% share). The assets
to be sold to Crosstex consist of the AIM Pipeline System in Mississippi; a
12.4% interest in the Seminole gas processing plant in Texas; the Conroe gas
plant and gathering system in Texas; the Black Warrior pipeline system in
Alabama; and two smaller systems - Aurora Centana and Cadeville in Louisiana.
The assets to be sold to ScissorTail consist of various gas processing plants
and gathering pipeline in eastern Oklahoma. The transactions are expected to
close by June 30, 2003. The sale to Crosstex is subject to regulatory approvals.
For information on subsequent events related to litigation and contingencies see
Note 8, Litigation section. For information on subsequent events related to debt
and other financing matters see Note 7.
22
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
Introduction
Duke Capital Corporation (collectively with its subsidiaries, the Company), is a
wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as
the parent of some of the Company's non-utility and other operations. The
Company provides financing and credit enhancement services for its subsidiaries
and conducts operations through its business segments. See Note 1 to the
Consolidated Financial Statements for descriptions of the Company's business
segments.
Management's Discussion and Analysis should be read in conjunction with the
Consolidated Financial Statements.
RESULTS OF OPERATIONS
For the three months ended March 31, 2003, net income was $155 million, compared
with net income of $174 million for the same period in 2002. The decrease was
due primarily to charges related to changes in accounting principles of $52
million. Those changes included an after-tax charge of $42 million related to
the implementation of the Emerging Issues Task Force (EITF) Issue No. 02-03,
"Issued Involved in Accounting for Derivative Contracts Held for Trading
Purposes and for Contracts Involved in Energy Trading and Risk Management
Activities" and a charge of $10 million due to the implementation of Statement
of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset
Retirement Obligations."
Total consolidated operating revenues for the three months ended March 31, 2003
increased $2,235 million to $4,443 million from $2,208 million for the three
months ended March 31, 2002. The increase resulted primarily from significantly
higher natural gas liquid (NGL) pricing; two additional months of
transportation, storage and distribution revenues from assets acquired or
consolidated as part of the Westcoast Energy Inc. (Westcoast) acquisition in
March 2002; and the adoption of the final consensus on EITF Issue No. 02-03 upon
which the Company began to recognize revenues for certain natural gas and other
contracts on a gross basis. Adopting the final consensus on EITF Issue No. 02-03
did not require a change to prior periods, and therefore the Company did not
change 2002 operating revenue and operating expense amounts.
Total consolidated operating expenses for the three months ended March 31, 2003
increased $2,016 million to $3,885 million from $1,869 million for the three
months ended March 31, 2002. The increase resulted primarily from significantly
higher NGL pricing; two additional months of operating expenses from assets
acquired or consolidated as part of the Westcoast acquisition in March 2002; and
the adoption of the final consensus on EITF Issue No. 02-03, after which the
Company began to present revenues and expenses for certain natural gas
transactions on a gross basis in 2003. Adopting the final consensus on EITF
Issue No. 02-03 did not require a change to prior periods and therefore the
Company did not change the 2002 operating revenue and operating expense amounts.
Operating income was $558 million and earnings before interest and taxes (EBIT)
were $629 million for the three months ended March 31, 2003. This compares to
operating income of $339 million and EBIT of $418 million for the same period in
2002. Operating income and EBIT are affected by the same fluctuations for the
Company and each of its business segments. The following table shows the
components of EBIT and reconciles consolidated operating income and EBIT to net
income.
23
- --------------------------------------------------------------------------------
Reconciliation of Operating Income and EBIT to Net Income (in millions)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
----------------------------------
2003 2002
----------------------------------
Operating income $558 $339
Other income and expenses 71 79
----------------------------------
EBIT 629 418
Interest expense 278 140
Minority interest expense 41 21
----------------------------------
Earnings before income taxes 310 257
Income taxes 103 83
----------------------------------
Income before cumulative
effect of changes in accounting
principles 207 174
Cumulative effect of changes in
accounting principles, net of tax (52) -
----------------------------------
Net income $155 $174
================================================================================
EBIT for the three months ended March 31, 2003 increased $211 million to $629
million from $418 million for the three months ended March 31, 2002. The
increase resulted primarily from two additional months of transportation,
storage and distribution income from assets acquired or consolidated as part of
the Westcoast acquisition.
For a more detailed discussion of EBIT, see segment discussions below.
EBIT may be viewed as a non-Generally Accepted Accounting Principles (GAAP)
measure under the rules of the Securities and Exchange Commission (SEC). The
Company has included EBIT in its disclosures because it is the primary
performance measure used by management to evaluate total company and segment
performance. On a segment basis, it includes all profits (both operating and
non-operating) before deducting interest and taxes, and is net of the minority
interest expense related to those profits. Management believes EBIT is a good
indicator of each segment's operating performance, as it represents the results
of the Company's ownership interests in operations without regard to financing
methods or capital structure. As an indicator of the Company's operating
performance, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with GAAP. The
Company's EBIT may not be comparable to a similarly titled measure of another
company because other entities may not calculate EBIT in the same manner.
Business segment EBIT is summarized in the following table, and detailed
discussions follow.
24
- -------------------------------------------------------------------------------
EBIT by Business Segment (in millions)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
----------------------------
2003 2002
----------------------------
Natural Gas Transmission $423 $ 266
Field Services 33 35
Duke Energy North America 21 46
International Energy 54 57
Other Operations 20 4
Other /a/ 34 (49)
----------------------------
Total Segment EBIT 585 359
EBIT attributable to:
Minority Interests 46 14
Third Party Interest Income 3 36
Foreign Currency (Loss) Gain (5) 9
----------------------------
Consolidated EBIT $629 $ 418
- -------------------------------------------------------------------------------
/a/ Other primarily includes certain unallocated corporate costs and elimination
of intersegment profits.
The amounts discussed below include intercompany transactions that are
eliminated in the Consolidated Financial Statements.
Natural Gas Transmission
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
--------------------------
(in millions, except where noted) 2003 2002
- -------------------------------------------------------------------------------
Operating revenues $ 968 $450
Operating expenses 567 218
--------------------------
Operating income 401 232
Other income, net of expenses 35 37
Minority interest expense 13 3
--------------------------
EBIT $ 423 $266
==========================
Proportional throughput, TBtu /a/ 1,082 670
- -------------------------------------------------------------------------------
/a/ Trillion British thermal units
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $518 million to $968 million from $450 million for the three months
ended March 31, 2002. This increase resulted primarily from January and February
2003 transportation, storage and distribution revenue of $466 million from
assets acquired or consolidated as a part of the Westcoast acquisition in March
2002. Revenues also increased $10 million due to business expansion projects.
Operating revenues for the month of March 2003 versus the month of March 2002
also increased approximately $30 million due to increased natural gas prices and
volumes at Union Gas Limited (Union Gas), the natural gas distribution
operations in Ontario.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $349 million to $567 million from $218 million for the three months
ended March 31, 2002. This increase was due primarily to incremental operating
expenses of $319 million related to January and February 2003 operations of the
gas transmission, storage and distribution assets acquired or consolidated in
the Westcoast acquisition in March 2002. Operating expenses for the month of
March 2003 versus the month of March 2002 also increased approximately $30
million due to increased natural gas prices and volumes at Union Gas.
25
Minority Interest Expense. Minority interest expense for the three months ended
March 31, 2003 increased $10 million to $13 million from $3 million for the
three months ended March 31, 2002. This increase resulted from recognizing a
full quarter of minority interest expense in 2003, versus only one month during
the first quarter of 2002, from less than wholly owned subsidiaries acquired in
the March 2002 acquisition of Westcoast.
EBIT. EBIT for the three months ended March 31, 2003 increased $157 million to
$423 million from $266 million for the three months ended March 31, 2002. As
discussed above, this increase resulted primarily from incremental EBIT related
to assets acquired or consolidated as part of the March 2002 acquisition of
Westcoast, which contributed $135 million of incremental EBIT to first quarter
2003. First quarter 2003 and 2002 results both include gains of $14 million from
the sales of Natural Gas Transmission's limited partnership interests in
Northern Borders Partners L.P.
Field Services
-------------------------------------------------------------------------------------------
Three Months Ended
March 31,
---------------------------
(in millions, except where noted) 2003 2002
-------------------------------------------------------------------------------------------
Operating revenues $2,472 $1,134
Operating expenses 2,426 1,099
---------------------------
Operating income 46 35
Other income, net of expenses 15 8
Minority interest expense 28 8
---------------------------
EBIT $ 33 $ 35
===========================
Natural gas gathered and processed/transported, TBtu/d /a/ 8.0 8.4
NGL production, MBbl/d /b/ 375.2 388.6
Average natural gas price per MMBtu /c/ $ 6.59 $ 2.32
Average NGL price per gallon /d/ $ 0.58 $ 0.31
-------------------------------------------------------------------------------------------
/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
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $1,338 million to $2,472 million from $1,134 million for the same
period in 2002. The increase was primarily driven by increases of approximately
$1,406 million on the sale of natural gas, NGLs and other petroleum products.
These increases were mainly driven by a $0.27 per gallon increase in average NGL
prices, and a $4.27 per MMBtu increase in natural gas prices. Partially
offsetting the NGL and natural gas price increases were reduced levels of
natural gas gathered and processed/transported (throughput) of 0.4 TBtu per day.
Also contributing to higher revenues were increased transportation, storage and
processing fees, offset by a decrease in net trading margin and losses resulting
from hedging activity.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $1,327 million to $2,426 million from $1,099 million for the same
period in 2002. The increase was due primarily to increases of approximately
$1,314 million in expenses related to purchases of natural gas, NGLs and other
petroleum products. These increases were mainly driven by a $0.27 per gallon
increase in average NGL prices, and a $4.27 per MMBtu increase in natural gas
prices. Partially offsetting the NGL and natural gas price increases were
reduced levels of natural gas gathered and processed/transported (throughput) of
0.4 TBtu per day. Also contributing to the increase in expenses were slightly
higher operating and maintenance, and depreciation costs.
26
Minority Interest Expense. Minority interest expense for the three months ended
March 31, 2003 increased $20 million to $28 million from $8 million for the
three months ended March 31, 2002. This increase was due primarily to increased
earnings from Duke Energy Field Services, LLC (DEFS), the Company's joint
venture with ConocoPhillips.
EBIT. The decrease in EBIT of $2 million was largely the result of higher NGL
prices being substantially offset by higher natural gas prices, hedging activity
and increases in minority interest expense.
Duke Energy North America (DENA)
- --------------------------------------------------------------------------
Three Months Ended
March 31,
--------------------
(in millions, except where noted) 2003 2002
- --------------------------------------------------------------------------
Operating revenues $ 1,221 $ 256
Operating expenses 1,209 206
--------------------
Operating income 12 50
Other income (loss), net of expenses 9 (5)
Minority interest benefit - (1)
--------------------
EBIT $ 21 $ 46
====================
Actual plant production, GWh 5,110 3,868
Proportional megawatt capacity in operation 14,156 7,515
- --------------------------------------------------------------------------
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $965 million to $1,221 million from $256 million for the same period
in 2002. Increases in net generation assets in operation and in the average
price realized for electricity generated, resulted in a $120 million increase in
operating revenue. In addition, revenues increased $850 million in connection
with the implementation of the remaining provisions of EITF Issue No. 02-03. As
a result of adopting EITF Issue No. 02-03 on January 1, 2003, gains and losses
for certain derivative and non-derivative contracts that were previously
reported on a net basis in Trading and Marketing Net Margin under EITF Issue No.
98-10 are now reported on a gross basis. Specifically, the $850 million increase
is primarily related to the presentation effective on January 1, 2003, of
certain derivative contracts related to DENA's wholesale natural gas marketing
operations and the presentation of gains and losses from the settlement of many
non-derivative contracts on a gross basis in the Consolidated Statements of
Income. These increases were partially offset by decreased net margins due to
lower proprietary trading results.
The Company adopted EITF Issue No. 02-03 and did not change the 2002 operating
revenue and operating expense amounts.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $1,003 million to $1,209 million from $206 million for the same period
in 2002. Changes in volumes and prices surrounding merchant generation plants
contributed $113 million to this increase. Similar to the increase in operating
revenues discussed above, operating expenses also increased $815 million due to
the adoption of the final consensus on EITF Issue No. 02-03. Also contributing
to the increase in operating expenses was increased depreciation expense of $28
million, related primarily to eight new plants going into commercial operation
and /or acquired in the second quarter of 2002. Additionally, these increases in
operating expenses were partially offset by lower general and administrative
expenses in 2003 as a result of DENA's realignment of its operations at the end
of 2002.
EBIT. EBIT for the three months ended March 31, 2003, decreased $25 million to
$21 million from $46 million for the same period in 2002. The decline was
primarily driven by lower proprietary trading results and the increased
operating expenses as discussed above. These EBIT decreases were partially
offset by increases in other income, net of expenses of $14 million. The
increase in other income, net of expenses was due primarily to higher equity
earnings from American Ref-Fuel Company, LLC which owns and operates facilities
that convert waste to energy.
27
In March 2003, DENA entered into an agreement to sell its 50% ownership interest
in Duke/UAE Ref-Fuel LLC for $306 million to Highstar Renewable Fuels LLC.
Duke/UAE Ref-Fuel LLC owns American Ref-Fuel Company LLC, a holding company for
six waste-to-energy facilities in the northeastern U.S. The transaction, which
is subject to a number of conditions including certain regulatory approvals, is
expected to be finalized later in 2003 and DENA expects to record a gain upon
completion of this transaction.
International Energy
- -----------------------------------------------------------------------------------------
Three Months Ended
March 31,
---------------------
(in millions, except where noted) 2003 2002
- -----------------------------------------------------------------------------------------
Operating revenues $ 382 $ 289
Operating expenses 331 235
---------------------
Operating income 51 54
Other income, net of expenses 8 8
Minority interest expense 5 5
---------------------
EBIT $ 54 $ 57
=====================
Sales, GWh 4,759 4,932
Proportional megawatt capacity in operation 4,887 4,705
Proportional maximum pipeline capacity in operation, MMcf/d/a/ 363 363
- -----------------------------------------------------------------------------------------
/a/ Million cubic feet per day
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $93 million to $382 million from $289 million for the same period in
2002. Of this increase $148 million was due to the adoption of the final
consensus on EITF Issue No. 02-03. As a result of implementing EITF Issue No.
02-03, International Energy began to recognize certain natural gas transactions
on a gross basis in 2003. International Energy adopted EITF Issue No. 02-03 and
did not change 2002 operating revenue and operating expense amounts. Also
contributing to the increase in revenues were $20 million in revenues from
assets acquired in France during 2002, $13 million from increased energy prices
and GWhs sold at International Energy's Latin American operating facilities, and
$18 million from increased gas prices related to liquefied natural gas
operations. These increases were partially offset by a one-time increase in 2002
revenues for the final guidance in Brazil on free energy exposure related to
rationing of $91million, and the negative impacts of currency devaluations
within Brazil and Argentina of $21 million.
Operating Expenses. Operating expenses for the three months ended March 31,
2003, increased $96 million to $331 million from $235 million for the same
period in 2002. Similar to the increase in operating revenues described above,
operating expenses increased $148 million due to the adoption of the final
consensus on EITF Issue No. 02-03. Additionally, increased fuel expenses from
assets acquired in France contributed expenses of $9 million; increased prices
and generation within International Energy's Latin America operating facilities
added $14 million of expenses; and increased prices on gas purchased to cover
liquefied natural gas contracts increased expenses by $17 million. Increased
operating expenses were partially offset by a one-time increase in 2002 expenses
for the final guidance in Brazil on free energy exposures related to rationing
of $91 million and favorable impacts of $13 million due to currency devaluations
within Brazil and Argentina.
EBIT. For the three months ended March 31, 2003, International Energy reported
EBIT of $54 million, compared to EBIT of $57 million for the same period in
2002. Included in International Energy's first quarter 2003 EBIT is a
non-recurring, non-cash charge of $11 million related to the timing of revenue
recognition at the Cantarell investment in Mexico, a nitrogen-production plant
which was acquired with Westcoast.
28
Other Operations
- ------------------------------------------------------------------------
Three Months Ended
March 31,
--------------------
(in millions) 2003 2002
- ------------------------------------------------------------------------
Operating revenues $ 81 $ 163
Operating expenses 80 172
--------------------
Operating (loss) income 1 (9)
Other income, net of expenses 19 12
Minority interest benefit - (1)
--------------------
EBIT $ 20 $ 4
- ------------------------------------------------------------------------
Operating Revenues. Operating revenues for the three months ended March 31, 2003
decreased $82 million to $81 million from $163 million for the same period in
2002. The decrease was due primarily to the sale of Duke Engineering & Services,
Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) in 2002, which contributed
$125 million to revenues during the first quarter of 2002. The decrease in
operating revenues was partially offset by an increase in revenues at Energy
Delivery Services (EDS) of $41 million. EDS was formed in the second quarter of
2002.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
decreased $92 million to $80 million from $172 million for the same period in
2002. Similar to the decrease in operating revenues described above, the
decrease in operating expenses was due primarily to the sale of DE&S and
DukeSolutions in 2002 which contributed $122 million to operating expenses
during the first quarter of 2002. Operating expenses for the first quarter of
2002 also included a $15 million reserve for the expected loss associated with
the sale of DukeSolutions. The sale of DukeSolutions was completed on May 1,
2002. The decrease in operating expenses was partially offset by an increase in
operating expenses at EDS of $41 million.
EBIT. EBIT for the three months ended March 31, 2003 increased $16 million to
$20 million from $4 million for the same period in 2002. The increase in EBIT
was impacted by the same factors discussed above under operating revenues and
operating expenses.
Other Impacts on Net Income
For the three months ended March 31, 2003, interest expense increased $138
million compared to the same period in 2002. The increase was due primarily to
higher debt balances resulting from debt assumed in, and issued with respect to,
the acquisition of Westcoast; and lower capitalized interest for DENA; and
additional debt.
Minority interest expense increased $20 million for the three months ended March
31, 2003, as compared to the same period in 2002. Minority interest expense
includes expense related to regular distributions on preferred securities of the
Company and its subsidiaries, which decreased for the three months ended March
31, 2003, as compared to the same period in 2002. The decrease in 2003 was due
primarily to lower distributions related to Catawba River Associates, LLC.
Beginning in October 2002, costs associated with this financing have been
classified as interest expense.
Minority interest expense as shown and discussed in the preceding business
segment EBIT sections includes only minority interest expense related to EBIT of
the Company's joint ventures. It does not include minority interest expense
related to interest and taxes of the joint ventures. Total minority interest
expense related to the joint ventures (including the portion related to interest
and taxes) decreased $28 million for the three months ended March 31, 2003, as
compared to the same period for 2002. The 2003 change was driven by increased
earnings from DEFS and from recognizing a full quarter of minority interest
expense in 2003, versus only one month during the first quarter of 2002, from
less than wholly owned subsidiaries acquired in the March 2002 acquisition of
Westcoast.
29
During the first quarter of 2003, the Company recorded a net-of-tax and minority
interest cumulative effect adjustment for change in accounting principles of $52
million, as a reduction in earnings. The change in accounting principles
included an after-tax and minority interest charge of $42 million related to the
implementation of EITF Issue No. 02-03 (see Note 2 to the Consolidated Financial
Statements) and a charge of $10 million due to the implementation of SFAS No.
143, (see Notes 2 and 6 to the Consolidated Financial Statements).
LIQUIDITY AND CAPITAL RESOURCES
As of March 31, 2003, the Company had $972 million in cash and cash equivalents
compared to $814 million as of December 31, 2002. The Company's working capital
was a $549 million deficit as of March 31, 2003, compared to a $237 million
deficit as of December 31, 2002. The Company relies upon cash flows from
operations, as well as borrowings and the sale of assets to fund its liquidity
and capital requirements. A material adverse change in operations or available
financing may impact the Company's ability to fund its current liquidity and
capital resource requirements.
Operating Cash Flows
Net cash provided by operations decreased $203 million for the three months
ended March 31, 2003 when compared to the same period in 2002. The decrease in
cash provided by operating activities was due primarily to higher cash earnings
being more than offset by a decrease in working capital and changes in net
realized and unrealized mark-to-market and hedging transactions.
Investing Cash Flows
Net cash used in investing activities decreased $2,941 million for the three
months ended March 31, 2003 when compared to the same period in 2002. Capital
and investment expenditures decreased $2,513 million for the three months ended
March 31, 2003 when compared to the same period in 2002. Decreased capital
expenditures were due primarily to the 2002 acquisition of Westcoast for $1,690
million in cash, net of cash acquired (see Note 3 to the Consolidated Financial
Statements), a decrease in DENA's investments in generating facilities, and a
decrease in investments in property, plant and equipment at Field Services and
International Energy. Investment activities also decreased in 2003 compared to
2002, due primarily to reduced investments at Other Operations (primarily
related to Duke Capital Partners, LLC) and Natural Gas Transmission's investment
in a 50% interest in Gulfstream Natural Gas System, LLC.
Financing Cash Flows and Liquidity
Cash flows from financing activities decreased $2,443 million for the three
months ended March 31, 2003 when compared to the same period in 2002. This
change is due primarily to the reduction of outstanding debt during the first
quarter of 2003 as compared to the same period in 2002 when the Company acquired
Westcoast and financed other business expansion projects. In addition, this
change in cash flows from financing activities is aligned with the Company's
strategy to improve its balance sheet leverage through the reduction of
outstanding debt.
The Company's cash requirements for 2003 are expected to be funded by cash from
operations and the sale of assets, and to be adequate for funding capital
expenditures and repaying approximately $2,500 million of debt in 2003. During
the first four months of 2003, the Company announced or completed asset sales of
approximately $1,100 million in gross proceeds, including $58 million of assumed
debt. In addition, the Company may opportunistically access the capital markets.
The ability to access the capital markets is dependent upon market opportunities
presented, among other factors. The Company does not have any material
off-balance sheet financing entities or structures, except for normal operating
lease arrangements and guarantee contracts (see Note 9 to the Consolidated
Financial Statements). Management believes the Company has adequate financial
flexibility and resources to meet its future needs.
30
Credit Ratings. In March 2003, Moody's Investor Service (Moody's) placed its
long-term and short-term ratings of the Company and DEFS, and its long-term
ratings of Texas Eastern Transmission, LP and PanEnergy Corp, on review for
potential downgrade. Moody's review was prompted by concerns regarding the
Company's cash flow coverage metrics and uncertainties associated with
forecasting cash flow contributions from DENA and Duke Energy International,
LLC. Moody's review of DEFS was prompted by perceived pressures on DEFS' debt
coverage ability.
The following table summarizes the credit ratings of the Company, its principal
funding subsidiaries and its trading and marketing subsidiary Duke Energy
Trading and Marketing, LLC, as of March 31, 2003.
- ------------------------------------------------------------------------------------------------------------------------
Credit Ratings Summary as of March 31, 2003
- ------------------------------------------------------------------------------------------------------------------------
Standard Moody's Investor Dominion Bond
and Poors Service Fitch Ratings Rating Service
Duke Capital Corporation/a/ BBB+ Baa2 BBB Not applicable
Duke Energy Field Services/a/ BBB Baa2 BBB Not applicable
Texas Eastern Transmission, LP/a/ A- Baa1 BBB+ Not applicable
Westcoast Energy Inc./a/ A- Not applicable Not applicable A(low)
Union Gas Limited/a/ A- Not applicable Not applicable A
Maritimes and Northeast Pipeline, LLC/b/ A A1 Not applicable Not applicable
Maritimes and Northeast Pipeline, LP/b/ A A1 Not applicable A
Duke Energy Trading and Marketing, LLC/c/ BBB Not applicable Not applicable Not applicable
- ------------------------------------------------------------------------------------------------------------------------
/a/ Represents senior unsecured credit rating
/b/ Represents senior secured credit rating
/c/ Represents corporate credit rating
The Company's credit ratings are dependent on, among other factors, the ability
to generate sufficient cash to fund the Company's capital and investment
expenditures, while strengthening the balance sheet through debt reductions. If,
as a result of market conditions or other factors affecting the Company's
business, the Company is unable to execute its business plan, including
disposition of non-core assets, or if the its earnings outlook deteriorates, the
Company's ratings could be further affected.
To date, the impacts of the credit rating downgrades on the Company and its
subsidiaries have been minimal. If further downgrades were to occur and to the
extent that these downgrades placed the Company or its subsidiaries below
investment grade, there could be a negative impact on the respective entity's
working capital and terms of trade.
For a discussion of the Company's significant financing activities, credit
facilities and related borrowings and effective SEC and Canadian shelf
registrations, see Note 7 to the Consolidated Financial Statements.
CURRENT ISSUES
For information on current issues related to the Company, see the following
Notes to the Consolidated Financial Statements: Note 5, Regulatory Matters, and
Note 8, Commitments and Contingencies.
New Accounting Standards
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." In June 2002, the Financial Accounting Standards Board (FASB)
issued SFAS No. 146 which addresses accounting for restructuring and similar
costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF
Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit
31
an Activity (including Certain Costs Incurred in a Restructuring)." The Company
has adopted the provisions of SFAS No. 146 for restructuring activities
initiated after December 31, 2002. SFAS No. 146 requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost
was recognized on the date of the Company's commitment to an exit plan. SFAS No.
146 also establishes that the liability should initially be measured and
recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of
recognizing future restructuring costs as well as the amounts recognized.
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." In April 2003, the FASB issued SFAS No. 149, which amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. SFAS No. 149 clarifies the discussion around initial net investment and
when a derivative contains a financing component, and amends the definition of
the term underlying to conform it to language used in FASB Interpretation No.
45, "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others. "In addition, SFAS No.
149 also incorporates certain Derivative Implementation Group Implementation
Issues. The provisions of SFAS No. 149 are effective for contracts entered into
or modified after June 30, 2003, and for hedging relationships designated after
June 30, 2003. The guidance should be applied to hedging relationships on a
prospective basis. The Company is currently assessing the impact SFAS No. 149
will have on its consolidated results of operations, cash flows and financial
position.
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities." In January 2003, the FASB issued FIN 46 which requires the primary
beneficiary a variable interest entity's activities to consolidate the variable
interest entity. The primary beneficiary is the party that absorbs a majority of
the expected losses and/or receives a majority of the expected residual returns
of the variable interest entity's activities. FIN 46 is immediately applicable
to variable interest entities created, or interests in variable interest
entities obtained, after January 31, 2003. For variable interest entities
created, or interests in variable interest entities obtained, on or before
January 31, 2003, FIN 46 is required to be applied in the first fiscal year or
interim period beginning after June 15, 2003. FIN 46 may be applied
prospectively with a cumulative-effect adjustment as of the date it is first
applied, or by restating previously issued financial statements with a
cumulative-effect adjustment as of the beginning of the first year restated. FIN
46 also requires certain disclosures of an entity's relationship with variable
interest entities. The Company has not identified any variable interest entities
created, or interests in variable entities obtained, after January 31, 2003 and
continues to assess the existence of any interests in variable interest entities
created on or prior to January 31, 2003. It is reasonably possible that the
Company will disclose information about a variable interest entity upon the
application of FIN 46, primarily as the result of investments it has in certain
unconsolidated affiliates. Any significant exposure to losses related to these
entities would be related to guarantee obligations as discussed in Note 9 to the
Consolidated Financial Statments. The Company is currently assessing FIN 46 but
does not anticipate that it will have a material impact on its consolidated
results of operations, cash flows or financial position.
Subsequent Events
In April 2003, the Company closed on substantially all elements of a transaction
to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada
Marketing and Aux Sable natural gas liquids plant to Enbridge Inc. and Fort
Chicago Energy Partners L.P. for approximately $250 million. This sale resulted
in an immaterial net loss. The transaction was completed except for the
Company's small ownership interest related to the U.S. segment of Alliance
Pipeline, which is expected to close in October 2003 and represents
approximately $11 million in proceeds. Alliance Pipeline extends from Fort St.
John in British Columbia to Chicago, Illinois. The Aux Sable plant extracts
natural gas liquids at the outlet of the Alliance Pipeline in Chicago. The
Company obtained its minority ownership interest in the Alliance natural gas
pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant
through its acquisition of Westcoast in 2002.
In April 2003, the Company sold all its Class B units of TEPPCO Partners, L.P.
(TEPPCO) for approximately $114 million. The Company recorded a pre-tax gain of
approximately $11 million on the sale. TEPPCO is a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil.
32
In April and May 2003, DEFS entered into two separate purchase and sale
agreements by which it will sell one package of assets to Crosstex Energy
Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy,
LLC (ScissorTail) for a total sales price of approximately $91 million, plus or
minus various adjustments to be made at closing. The gain on the sale will be
approximately $17 million (at the Company's approximately 70% share). The assets
to be sold to Crosstex consist of the AIM Pipeline System in Mississippi; a
12.4% interest in the Seminole gas processing plant in Texas; the Conroe gas
plant and gathering system in Texas; the Black Warrior pipeline system in
Alabama; and two smaller systems - Aurora Centana and Cadeville in Louisiana.
The assets to be sold to ScissorTail consist of various gas processing plants
and gathering pipeline in eastern Oklahoma. The transactions are expected to
close by June 30, 2003. The sale to Crosstex is subject to regulatory approvals.
For information on subsequent events related to litigation and contingencies see
Note 8 to the Consolidated Financial Statements, Litigation section. For
information on subsequent events related to debt and other financing matters see
Note 7 to the Consolidated Financial Statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
As of March 31, 2003, there have been no material changes in the Company's
qualitative and quantitative disclosures about market risk since December 31,
2002. See "Management's Discussion and Analysis of Results of Operations and
Financial Condition, Quantitative and Qualitative Disclosures About Market Risk"
in the Company's Form 10-K for December 31, 2002 for additional information on
the year end disclosures.
Item 4. Controls and Procedures.
During April and May 2003, the Company's management, including the Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness of
the Company's disclosure controls and procedures as defined in Exchange Act Rule
13a-14. Based on that evaluation, they concluded that the disclosure controls
and procedures are effective in ensuring that all material information required
to be filed in this quarterly report has been made known to them in a timely
fashion. The required information was effectively recorded, processed,
summarized and reported within the time period necessary to prepare this
quarterly report. The Company's disclosure controls and procedures are effective
in ensuring that information required to be disclosed in the Company's reports
under the Exchange Act are accumulated and communicated to management, including
the Chief Executive Officer and the Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure. There have been no
significant changes in internal controls, or in factors that could significantly
affect internal controls, after the Chief Executive Officer and Chief Financial
Officer completed their evaluation.
33
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
In late 1999, the Company discovered that operations and maintenance personnel
at its Moss Landing, California facility were occasionally "backflushing," a
practice initially implemented by the facility's prior owner, to remove debris
from the inlet side of the condensers. The flow of wastewater from this practice
was not specifically authorized in the facility's discharge permit. Upon its
discovery, the Company promptly reported the noncompliance to the California
Regional Water Quality Control Board (Control Board) and stopped the discharges.
After ongoing discussions of this matter, the Company and the Control Board have
agreed to the terms of a stipulated order with a civil penalty of $250,000, the
bulk of which will be paid as a Supplemental Environmental Project. The Control
Board is expected to formally approve the stipulated order in May 2003.
For additional information concerning litigation and other contingencies, see
Note 8 to the Consolidated Financial Statements, "Commitments and
Contingencies;" and Item 3, "Legal Proceedings," and Note 13 to the Consolidated
Financial Statements, "Commitments and Contingencies," in the Company's Form
10-K for December 31, 2002, which are incorporated herein by reference.
Management believes that the final disposition of these proceedings will have no
material adverse effect on the Company's consolidated results of operations,
cash flows or financial position.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
Exhibit
Number
- ------
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
The total amount of securities of the registrant or its subsidiaries authorized
under any instrument with respect to long-term debt not filed as an exhibit does
not exceed 10% of the total assets of the registrant and its subsidiaries on a
consolidated basis. The registrant agrees, upon request of the Securities and
Exchange Commission, to furnish copies of any or all of such instruments.
(b) Reports on Form 8-K
The Company filed no reports on Form 8-K during the first quarter of
2003.
34
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DUKE CAPITAL CORPORATION
Date: May 16, 2003 /s/ Robert P. Brace
---------------------------------
Robert P. Brace
Chairman of the Board and
President
Date: May 16, 2003 /s/ Keith G. Butler
---------------------------------
Keith G. Butler
Controller and
Chief Financial Officer
35
CERTIFICATIONS
I, Keith G. Butler, certify that:
1) I have reviewed this quarterly report on Form 10-Q of Duke Capital
Corporation;
2) Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 16, 2003 /s/ Keith G. Butler
--------------------------------
Keith G. Butler
Controller and
Chief Financial Officer
36
CERTIFICATIONS
I, Robert P. Brace, certify that:
1) I have reviewed this quarterly report on Form 10-Q of Duke Capital
Corporation;
2) Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 16, 2003 /s/ Robert P. Brace
-----------------------------------
Robert P. Brace
Chairman of the Board and
President
37