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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 June 30, 2002 Commission File Number 0-23977
DUKE CAPITAL CORPORATION
(Exact name of Registrant as Specified in its Charter)
Delaware 51-0282142
(State or Other Jurisdiction of Incorporation) (IRS Employer Identification No.)
526 South Church Street
Charlotte, NC 28202-1904
(Address of Principal Executive Offices)
(Zip code)
704-594-6200
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes x No __
---
All of the Registrant's common shares are directly owned by Duke Energy
Corporation (File No. 1-4928), which files reports and proxy materials pursuant
to the Securities Exchange Act of 1934.
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Number of shares of Common Stock, no par value, outstanding at July 31, 20021,
............1,010
DUKE CAPITAL CORPORATION
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2002
INDEX
Item Page
- ---- ----
PART I. FINANCIAL INFORMATION
1. Financial Statements ............................................................................. 1
Consolidated Statements of Income for the Three and Six Months Ended
June 30, 2002 and 2001 .................................................................. 1
Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 ........................ 2
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 2002 and 2001 .................................................................. 4
Consolidated Statements of Comprehensive Income for the Three and Six Months
Ended June 30, 2002 and 2001 ............................................................ 5
Notes to Consolidated Financial Statements ................................................... 6
2. Management's Discussion and Analysis of Results of Operations and Financial Condition ............ 20
PART II. OTHER INFORMATION
1. Legal Proceedings ................................................................................ 41
6. Exhibits and Reports on Form 8-K ................................................................. 41
Signatures ....................................................................................... 42
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Duke Capital Corporation's reports, filings and other public announcements may
contain or incorporate by reference statements that do not directly or
exclusively relate to historical facts. Such statements are "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995. You can typically identify forward-looking statements by the use of
forward-looking words, such as "may," "will," "could," "project," "believe,"
"anticipate," "expect," "estimate," "continue," "potential," "plan," "forecast"
and other similar words. Those statements represent our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors. Many of those factors are outside our
control and could cause actual results to differ materially from the results
expressed or implied by those forward-looking statements. Those factors include:
. state, federal and foreign legislative and regulatory initiatives that
affect cost and investment recovery, have an impact on rate
structures, and affect the speed at and degree to which competition
enters the electric and natural gas industries;
. the outcomes of litigation and regulatory proceedings or inquiries;
. industrial, commercial and residential growth in our service
territories;
. the weather and other natural phenomena;
. the timing and extent of changes in commodity prices, interest rates
and foreign currency exchange rates;
. changes in environmental and other laws and regulations to which we
and our subsidiaries are subject or other external factors over which
we have no control;
i
. the results of financing efforts, including our ability to obtain
financing on favorable terms, which can be affected by various
factors, including our credit ratings and general economic conditions;
. the level of creditworthiness of counterparties to our transactions;
. the amount of collateral required to be posted from time to time in
our transactions;
. growth in opportunities for our business units, including the timing
and success of efforts to develop domestic and international power,
pipeline, gathering, processing and other infrastructure projects;
. the performance of electric generation, pipeline and gas processing
facilities;
. the extent of success in connecting natural gas supplies to gathering
and processing systems and in connecting and expanding gas and
electric markets; and
. the effect of accounting policies issued periodically by accounting
standard-setting bodies.
In light of these risks, uncertainties and assumptions, the events described in
the forward-looking statements might not occur or might occur to a different
extent or at a different time than we have described.
ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In millions)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- --------
Operating Revenues
Sales, trading and marketing of natural gas
and petroleum products $ 8,330 $ 6,241 $ 12,856 $ 16,779
Trading and marketing of electricity 3,501 5,930 7,881 9,169
Transportation and storage of natural gas 447 233 773 479
Electric generation 198 136 455 281
Other 349 416 549 648
------- ------- -------- --------
Total operating revenues 12,825 12,956 22,514 27,356
------- ------- -------- --------
Operating Expenses
Natural gas and petroleum products purchased 8,023 6,104 12,402 16,216
Purchased power 3,376 5,418 7,506 8,066
Other operation and maintenance 526 600 1,095 1,144
Depreciation and amortization 238 167 426 329
Property and other taxes 63 39 124 84
------- ------- -------- --------
Total operating expenses 12,226 12,328 21,553 25,839
------- ------- -------- --------
Operating Income 599 628 961 1,517
Other Income and Expenses 22 28 69 38
Interest Expense 207 140 338 285
Minority Interest Expense 52 34 73 183
------- ------- -------- --------
Earnings Before Income Taxes 362 482 619 1,087
Income Taxes 123 168 206 385
------- ------- -------- --------
Income Before Cumulative Effect of Change in Accounting Principle 239 314 413 702
Cumulative Effect of Change in Accounting Principle, net of tax - - - (69)
------- ------- -------- --------
Net Income $ 239 $ 314 $ 413 $ 633
======= ======= ======== ========
See Notes to Consolidated Financial Statements.
1
CONSOLIDATED BALANCE SHEETS
(In millions)
June 30, December 31,
2002 2001
(unaudited)
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 54 $ 263
Receivables 6,237 5,098
Inventory 624 503
Unrealized gains on mark-to-market and hedging transactions 3,254 2,275
Other 703 411
--------- -----------
Total current assets 10,872 8,550
--------- -----------
Investments and Other Assets
Investments in affiliates 2,264 1,480
Goodwill, net of accumulated amortization 4,123 1,729
Notes receivable 641 576
Unrealized gains on mark-to-market and hedging transactions 4,953 2,824
Other 1,597 1,919
--------- -----------
Total investments and other assets 13,578 8,528
--------- -----------
Property, Plant and Equipment
Cost 29,465 21,147
Less accumulated depreciation and amortization 3,698 3,120
--------- -----------
Net property, plant and equipment 25,767 18,027
--------- -----------
Regulatory Assets and Deferred Debits 1,045 185
--------- -----------
Total Assets $ 51,262 $ 35,290
========= ===========
See Notes to Consolidated Financial Statements.
2
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
June 30, December 31,
2002 2001
(unaudited)
----------- ------------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 5,122 $ 4,111
Notes payable and commercial paper 2,525 1,466
Taxes accrued 511 114
Interest accrued 244 191
Current maturities of long-term debt 911 254
Unrealized losses on mark-to-market and hedging transactions 2,713 1,523
Other 1,348 1,789
-------- --------
Total current liabilities 13,374 9,448
-------- --------
Long-term Debt 13,971 9,124
-------- --------
Deferred Credits and Other Liabilities
Deferred income taxes 2,602 2,215
Unrealized losses on mark-to-market and hedging transactions 3,768 1,957
Other 2,076 589
-------- --------
Total deferred credits and other liabilities 8,446 4,761
-------- --------
Guaranteed Preferred Beneficial Interests in Subordinated
Notes of Duke Capital Corporation 825 824
-------- --------
Minority Interests in Financing Subsidiary 1,025 1,025
-------- --------
Minority Interests 1,971 1,221
-------- --------
Common Stockholder's Equity
Common stock, no par, 3,000 shares authorized,
1,010 shares outstanding - -
Paid-in capital 6,540 4,184
Retained Earnings 4,939 4,521
Accumulated other comprehensive income 171 182
-------- --------
Total common stockholder's equity 11,650 8,887
-------- --------
Total Liabilities and Stockholder's Equity $ 51,262 $ 35,290
======== ========
See Notes to Consolidated Financial Statements
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
Six Months Ended
June 30,
------------------------------
2002 2001
----------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 413 $ 633
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and amortization 426 329
Cumulative effect of change in accounting principle - 69
Deferred income taxes 24 322
(Increase) decrease in
Net unrealized mark-to-market and hedging transactions 93 (320)
Receivables 352 (958)
Inventory 41 (38)
Other current assets (209) 360
Increase (decrease) in
Accounts payable 570 981
Taxes accrued 331 (154)
Interest accrued 5 36
Other current liabilities (335) 353
Other, assets (74) 100
Other, liabilities (385) (151)
-------- ---------
Net cash provided by operating activities 1,252 1,562
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures, net of cash acquired (2,099) (1,914)
Investment expenditures (613) (588)
Acquisition of Westcoast Energy, Inc., net of cash acquired (1,690) -
Proceeds from the sale of subsidiaries 69 -
Notes receivable 134 45
Other 281 642
-------- ---------
Net cash used in investing activities (3,918) (1,815)
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 1,507 1,664
Payments for the redemption of long-term debt (523) (310)
Net change in notes payable and commercial paper 676 (1,161)
Contributions from minortiy interests 261 -
Capital contributions from parent 500 650
Other 36 (49)
-------- ---------
Net cash provided by financing activities 2,457 794
-------- ---------
Net (decrease) increase in cash and cash equivalents (209) 541
Cash and cash equivalents at beginning of period 263 587
-------- ---------
Cash and cash equivalents at end of period $ 54 $ 1,128
======== =========
Supplemental Disclosures
Cash paid for interest, net of amount capitalized $ 283 $ 277
Cash paid for income taxes $ 84 $ 191
Acquisition of Westcoast Energy, Inc.
Fair value of assets acquired $ 9,480
Liabilities assumed, including debt and minority interests 8,387
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 Six Months Ended
June 30, June 30,
---------------------- ---------------------
2002 2001 2002 2001
-------- ------- ------ -------
Net Income $ 239 $ 314 $ 413 $ 633
Other comprehensive income (loss), net of tax
Cumulative effect of change in accounting principle - - - (908)
Foreign currency translation adjustments (102) (47) (126) (184)
Net unrealized (losses) gains on cash flow hedges (73) 1,500 202 1,142
Reclassification into earnings 25 305 (87) 480
------ ------- ------ -------
Total other comprehensive (loss) income (150) 1,758 (11) 530
------ ------- ------ -------
Total Comprehensive Income $ 89 $ 2,072 $ 402 $ 1,163
====== ======= ====== =======
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 six business segments.
Natural Gas Transmission provides transportation, storage and distribution of
natural gas for customers throughout the east coast and southern portion of the
U.S. and Canada. Natural Gas Transmission provides gas gathering, processing and
transportation services to customers located in British Columbia, Canada and in
the Pacific northwest region of the U.S. Natural Gas Transmission does business
primarily through Duke Energy Gas Transmission Corporation. The Company acquired
Westcoast Energy, Inc. (Westcoast) on March 14, 2002 (see Note 3). Interstate
natural gas transmission and storage operations in the U.S. are subject to the
Federal Energy Regulatory Commission's (FERC) rules and regulations while
natural gas gathering, processing, transmission, distribution and storage
operations in Canada are subject to the rules and regulations of the National
Energy Board, the Ontario Energy Board and the British Columbia Utilities
Commission.
Field Services gathers, processes, transports, markets and stores natural gas
and produces, transports, markets and stores natural gas liquids (NGLs). It
conducts operations primarily through Duke Energy Field Services, LLC, which is
approximately 30% owned by Phillips Petroleum. Field Services operates gathering
systems in western Canada and 11 contiguous states in the U.S. Those systems
serve major natural gas-producing regions in the Rocky Mountain, Permian Basin,
Mid-Continent, East Texas-Austin Chalk-North Louisiana, and onshore and offshore
Gulf Coast areas.
Duke Energy North America (DENA) develops, operates and manages merchant
generation facilities and engages in commodity sales and services related to
natural gas and electric power. DENA conducts business throughout the U.S. and
Canada through Duke Energy North America, LLC and Duke Energy Trading and
Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil
Corporation. Beginning August 1, 2002, the Company's North American trading and
marketing functions currently in DENA, including DETM and the Canadian trading
operations, will be consolidated into one group.
International Energy develops, operates and manages natural gas transportation
and power generation facilities and engages in energy trading and marketing of
natural gas and electric power. It conducts operations primarily through Duke
Energy International, LLC and its activities target the Latin American,
Asia-Pacific and European regions.
Other Energy Services is composed of diverse energy businesses, operating
primarily through Duke/Fluor Daniel (D/FD) and Energy Delivery Services (EDS).
D/FD provides comprehensive engineering, procurement, construction,
commissioning and operating plant services for fossil-fueled electric power
generating facilities worldwide. It is a 50/50 partnership between the Company
and Fluor Enterprises, Inc., a wholly owned subsidiary of Fluor Corporation. EDS
is an engineering, construction, maintenance and technical services firm
specializing in electric transmission and distribution lines and substation
projects. It was formed in the second quarter of 2002 from the power delivery
services component of Duke Engineering & Services, Inc. (DE&S). This segment was
excluded from the sale of DE&S on April 30, 2002. Other Energy Services also
retained the portion of DukeSolutions, Inc. (DukeSolutions) that was not sold on
May 1, 2002. DE&S and DukeSolutions were included in Other Energy Services
through the date of their sale. For additional information on the sale of DE&S
and DukeSolutions, see Note 3.
Duke Ventures is composed of other diverse businesses, operating primarily
through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners, LLC (DCP).
6
Crescent develops high-quality commercial, residential and multi-family real
estate projects and manages land holdings primarily in the southeastern and
southwestern U.S. DukeNet develops and manages fiber optic communications
systems for wireless, local and long distance communications companies and
selected educational, governmental, financial and health care entities. DCP, a
wholly owned merchant banking company, provides debt and equity capital and
financial advisory services primarily to the energy industry.
2. Summary of Significant Accounting Policies
Consolidation. The Consolidated Financial Statements include the accounts of the
Company and all majority-owned subsidiaries, after eliminating significant
intercompany transactions and balances. These Consolidated Financial Statements
reflect all normal recurring adjustments that are, in the opinion of management,
necessary to present fairly the financial position and results of operations for
the respective periods. Amounts reported in the interim Consolidated Statements
of Income are not necessarily indicative of amounts expected for the respective
annual periods due to the effects of seasonal temperature variations on energy
consumption and the timing of maintenance on electric generating units.
Accounting for Hedges and Trading Activities. All derivatives not qualifying for
the normal purchases and sales exemption under Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities," are recorded on the Consolidated Balance Sheets at their fair value
as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. On the date that swaps, futures, forwards or option contracts are
entered into, the Company designates the derivative as either held for trading
(trading instrument); as a hedge of a forecasted transaction or future cash
flows (cash flow hedge); as a hedge of a recognized asset, liability or firm
commitment (fair value hedge); or as a normal purchase or sale contract.
For hedge contracts, the Company formally assesses, both at the hedge contract's
inception and on an ongoing basis, whether the hedge contract is highly
effective in offsetting changes in fair values or cash flows of hedged items. In
accordance with SFAS No. 133, a gain on the time value of options of $1 million
was excluded in the assessment and measurement of hedge effectiveness for the
three months ended June 30, 2002.
When available, quoted market prices or prices obtained through external sources
are used to verify a contract's fair value. For contracts with a delivery
location or duration for which quoted market prices are not available, fair
value is determined based on pricing models developed primarily from historical
and expected correlations with quoted market prices. As of June 30, 2002, 55% of
the trading contracts' fair value was determined using market prices and other
external sources and 45% was determined using pricing models.
Values are adjusted to reflect the potential impact of liquidating the positions
held in an orderly manner over a reasonable time period under current
conditions. Changes in market price and management estimates directly affect the
estimated fair value of these contracts. Accordingly, it is reasonably possible
that such estimates may change in the near term.
Trading. Prior to settlement of any energy contract held for trading purposes, a
favorable or unfavorable price movement is reported as Natural Gas and Petroleum
Products Purchased, or Purchased Power in the Consolidated Statements of Income.
An offsetting amount is recorded on the Consolidated Balance Sheets as
Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. When a contract to sell is physically settled, the fair value
entries are reversed and the gross amount invoiced to the customer is included
as Sales, Trading and Marketing of Natural Gas and Petroleum Products, or
Trading and Marketing of Electricity, in the Consolidated Statements of Income.
Similarly, when a contract to purchase is physically settled, the purchase price
is included as Natural Gas and Petroleum Products Purchased, or Purchased Power
in the Consolidated Statements of Income. If a contract is financially settled,
the unrealized gain or loss on the Consolidated Balance Sheets is reversed and
reclassified to a receivable or payable account. For income statement purposes,
financial settlement has no revenue presentation effect on the Consolidated
Statements of Income.
7
Cash Flow Hedges. Changes in the fair value of a derivative designated and
qualified as a cash flow hedge are included in the Consolidated Statements of
Comprehensive Income as Other Comprehensive Income (OCI) until earnings are
affected by the hedged item. Settlement amounts and ineffective portions of cash
flow hedges are removed from OCI and recorded in the Consolidated Statements of
Income in the same accounts as the item being hedged. The Company discontinues
hedge accounting prospectively when it is determined that the derivative no
longer qualifies as an effective hedge, or when it is no longer probable that
the hedged transaction will occur. When hedge accounting is discontinued because
the derivative no longer qualifies as an effective hedge, the derivative
continues to be carried on the Consolidated Balance Sheets at its fair value,
with subsequent changes in its fair value recognized in current-period earnings.
Gains and losses related to discontinued hedges that were previously accumulated
in OCI will remain in OCI until earnings are affected by the hedged item, unless
it is no longer probable that the hedged transaction will occur. Gains and
losses that were accumulated in OCI will be immediately recognized in
current-period earnings in those instances.
Fair Value Hedges. The Company enters into interest rate swaps to convert some
of its fixed-rate long-term debt to floating-rate long-term debt and designates
such interest rate swaps as fair value hedges. The Company also enters into
electricity derivative instruments such as swaps, futures and forwards to manage
the fair value risk associated with some of its unrecognized firm commitments to
sell generated power due to changes in the market price of power. Upon
designation of such derivatives as fair value hedges, prospective changes in the
fair value of the derivative and the hedged item are recognized in current
earnings in a manner consistent with the earnings effect of the hedged risk. All
components of each derivative gain or loss are included in the assessment of
hedge effectiveness, unless otherwise noted.
New Accounting Standards. The Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," as of January 1, 2002. SFAS No. 142 requires that goodwill
no longer be amortized over an estimated useful life, as previously required.
Instead, goodwill amounts are subject to a fair-value-based annual impairment
assessment. The Company did not recognize any material impairment due to the
implementation of SFAS No. 142. The standard also requires certain identifiable
intangible assets to be recognized separately and amortized as appropriate upon
reassessment. No adjustments to intangibles were identified by the Company at
transition.
The following table shows what net income would have been if amortization
(including any related tax effects) related to goodwill that is no longer being
amortized had been excluded from prior periods.
- --------------------------------------------------------------------------------
Goodwill - Adoption of SFAS No. 142 (in millions)
- --------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------
2002 2001 2002 2001
------------------------------------------------------------
Net Income
Reported net income $239 $314 $413 $633
Add back: Goodwill amortization, net of tax - 23 - 35
------------------------------------------------------------
Adjusted net income $239 $337 $413 $668
- ----------------------------------------------------------------------------------------------------------------
8
The changes in the carrying amount of goodwill for the six months ended June 30,
2002 and June 30, 2001 are as follows:
- ----------------------------------------------------------------------------------------------------------------
Goodwill (in millions)
- ----------------------------------------------------------------------------------------------------------------
Balance Acquired Balance
December 31, 2001 Goodwill Other June 30, 2002
-------------------------------------------------------------------------------
Natural Gas Transmission $ 481 $2,470 $ - $2,951
Field Services 571 - (90) 481
Duke Energy North America 91 - 18 109
International Energy 427 - - 427
Other Energy Services 5 - (4) 1
Other Operations 154 - - 154
-------------------------------------------------------------------------------
Total consolidated $1,729 $2,470 $(76) $4,123
- ----------------------------------------------------------------------------------------------------------------
Balance Acquired Balance
December 31, 2000 Goodwill Other June 30, 2001
-------------------------------------------------------------------------------
Natural Gas Transmission $ 299 $ - $123 $ 422
Field Services 507 - (26) 481
Duke Energy North America 12 - 2 14
International Energy 457 6 (51) 412
Other Energy Services 46 - (4) 42
Other Operations 183 - (14) 169
-------------------------------------------------------------------------------
Total consolidated $ 1,504 $ 6 $ 30 $1,540
- ----------------------------------------------------------------------------------------------------------------
The Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" on January 1, 2002. The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The new rules retain many of the fundamental recognition and
measurement provisions, but significantly change the criteria for classifying an
asset as held-for-sale or as a discontinued operation. Adoption of the new
standard had no material adverse effect on the Company's consolidated results of
operations or financial position.
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
143, "Accounting for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. The
standard applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and (or) normal use of the asset.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability is increased due to
the passage of time based on the time value of money until the obligation is
settled.
The Company is required and plans to adopt the provisions of SFAS No. 143 as of
January 1, 2003. To accomplish this, the Company must identify any legal
obligations for asset retirement obligations, and determine the fair value of
these obligations on the date of adoption. The determination of fair value is
complex and requires gathering market information and developing cash flow
models. Additionally, the Company will be required to develop processes to track
and monitor these obligations. Because of the effort needed to comply with the
adoption of SFAS No. 143, the Company is currently assessing the new standard
but has not yet determined the impact on its consolidated results of operations,
cashflows or financial position.
In June 2002, the FASB's Emerging Issues Task Force (EITF) reached a partial
consensus on Issue No. 02-03, "Recognition and Reporting of Gains and Losses on
Energy Trading Contracts under EITF Issues No.
9
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," and EITF No. 00-17, "Measuring the Fair Value of Energy-Related
Contracts in Applying Issue No. 98-10." The EITF concluded that, effective for
periods ending after July 15, 2002, mark-to-market gains and losses on energy
trading contracts (including those to be physically settled) must be shown on a
net basis in the Consolidated Statements of Income. Comparative financial
statements for prior periods must be reclassified to reflect presentation on a
net basis. Also, companies must disclose volumes of physically settled energy
trading contracts. The Company is evaluating the impact of this new consensus on
the presentation of its Consolidated Statements of Income, but believes it will
have a material impact on total revenues and expenses. The partial consensus
will have no impact on current or prior net income.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." The Company will adopt the provisions of
SFAS No. 146 for restructuring activities initiated after December 31, 2002.
SFAS No. 146 requires that the liability for costs associated with an exit or
disposal activity be recognized when the liability is incurred. Under EITF No.
94-3, a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized.
Reclassifications. Certain prior period amounts in the Consolidated Financial
Statements and Note 5 have been reclassified to conform to the current
presentation.
3. Business Acquisitions and Dispositions
Business Acquisitions. Using the purchase method for acquisitions, the Company
consolidates assets and liabilities as of the purchase date, and includes
earnings from acquisitions in consolidated earnings after the purchase date.
Assets acquired and liabilities assumed are recorded at estimated fair values on
the date of acquisition. The purchase price minus the estimated fair value of
the acquired assets and liabilities is recorded as goodwill. The allocation of
the purchase price may be adjusted if additional information on asset and
liability valuations becomes available within one year after the acquisition.
Acquisition of Westcoast Energy Inc. On March 14, 2002, the Company acquired
Westcoast for approximately $8 billion, including the assumption of $4.7 billion
of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a
wholly-owned subsidiary of Westcoast) and various project entities that are
wholly owned or consolidated by the Company. The interest rates on the assumed
debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through
2031. Westcoast, headquartered in Vancouver, British Columbia, is a North
American energy company with interests in natural gas gathering, processing,
transmission, storage and distribution, as well as power generation and
international energy businesses. In the transaction, a Company subsidiary
acquired all of the outstanding common shares of Westcoast in exchange for
approximately 49.9 million shares of Duke Energy common stock (including
exchangeable shares of a Duke Energy Canadian subsidiary that are substantially
equivalent to and exchangeable on a one-for-one basis for Duke Energy common
stock), and approximately $1.8 billion in cash. Under prorating provisions of
the acquisition agreement that ensured that approximately 50% of the total
consideration was paid in cash and 50% in stock, each common share of Westcoast
entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a
share of Duke Energy common stock or of an exchangeable share of a Duke Energy
Canadian subsidiary, or a combination thereof. The cash portion of the
consideration was funded with the proceeds from the issuance of $750 million in
mandatory convertible securities in November 2001 along with incremental
commercial paper. Duke Energy plans to retire the commercial paper later in 2002
and replace it with permanent capital in the form of equity or equity linked
securities. The timing for the equity or equity linked securities will be
dependent on the market opportunities presented. The Westcoast acquisition was
accounted for using the purchase method of accounting, and goodwill totaling
approximately $2.5 billion was recorded in the transaction.
10
The following unaudited pro forma consolidated financial results are presented
as if the acquisition had taken place at the beginning of the periods presented.
- -------------------------------------------------------------------------------------------------------------
Consolidated Pro Forma Results for the Company, including Westcoast (in millions)
- -------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------
2002 2001 2002 2001
-------------------------------------------------------------
Income Statement Data
Operating revenues $12,825 $14,259 $23,796 $32,039
Income before cumulative effect of change
in accounting principle 239 399 450 840
Cumulative effect of change in
accounting principle, net of tax - - - (69)
Net Income 239 399 450 771
- ----------------------------------------------- --------------- -------------- --------------- --------------
Dispositions. DE&S. On April 30, 2002, the Company completed the sale of
portions of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier)
for $74 million. Two components of DE&S were not part of the sale and remain
components of Other Energy Services. The Company established EDS in the second
quarter of 2002 from the transmission and distribution services component of
DE&S, and it will continue to supply transmission, distribution and substation
services to customers. Leadership of the U.S. Department of Energy Mixed Oxide
Fuel project also remains with the Company. Operating revenues in 2002 include
the resulting pre-tax gain of $21 million on the sale of DE&S.
DukeSolutions. On May 1, 2002, the Company completed the sale of portions of
DukeSolutions to Ameresco Inc. for $6 million. The portions that were not sold
remain a component of Other Energy Services. Operating expenses in 2002 include
the resulting pre-tax loss on the sale of DukeSolutions of $22 million.
4. Derivative Instruments, Hedging Activities and Credit Risk
Commodity Cash Flow Hedges. The Company's subsidiaries are exposed to market
fluctuations in the prices of various commodities related to their ongoing power
generating and natural gas gathering, processing and marketing activities. The
Company closely monitors the potential impacts of commodity price changes and,
where appropriate, enters into contracts to protect margins for a portion of its
future sales and generation revenues. The Company uses commodity instruments,
consisting of swaps, futures, forwards and collared options, as cash flow hedges
for natural gas, electricity and NGL transactions. The Company is hedging
exposures to the price variability of these commodities for a maximum of 30
years.
For the six months ended June 30, 2002, the ineffective portion of commodity
cash flow hedges was an after-tax net loss of $14 million and this amount was
not material for the six months ended June 30, 2001. As of June 30, 2002, $300
million of after-tax deferred net gains on derivative instruments were
accumulated on the Consolidated Balance Sheet in a separate component of
stockholder's equity, OCI, and are expected to be recognized in earnings during
the next 12 months as the hedged transactions occur. However, due to the
volatility of the commodities markets, the corresponding value in OCI will
likely change prior to its reclassification into earnings.
Commodity Fair Value Hedges. The Company's subsidiaries are exposed to changes
in the fair value of some unrecognized firm commitments to sell generated power
or natural gas due to market fluctuations in the underlying commodity prices.
The Company actively evaluates changes in the fair value of such unrecognized
firm commitments due to commodity price changes and, where appropriate, uses
various instruments to hedge its market risk. These commodity instruments,
consisting of swaps, futures and forwards, serve as fair value hedges for the
firm commitments associated with generated power and natural gas sales. The
Company is hedging exposures to the market risk of such items for a maximum of
23 years.
11
For the three and six months ended June 30, 2002 and 2001, the ineffective
portion of commodity fair value hedges was not material.
Trading Contracts. The Company provides energy supply, structured origination,
trading and marketing, risk management and commercial optimization services to
large energy customers, energy aggregators and other wholesale companies. These
services require the Company to use natural gas, electricity, NGL and
transportation derivatives and contracts that expose it to a variety of market
risks. The Company manages its trading exposure with strict policies that limit
its market risk and require daily reporting of potential financial exposure to
management. These policies include statistical risk tolerance limits using
historical price movements to calculate a daily earnings at risk measurement.
Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose
the Company to risk as a result of its issuance of variable-rate debt,
fixed-to-floating interest rate swaps, commercial paper and auction rate
preferred stock. The Company manages its interest rate exposure by limiting its
variable-rate and fixed-rate exposures to percentages of total capitalization,
as set by policy, and by monitoring the effects of market changes in interest
rates. The Company also enters into financial derivative instruments, including,
but not limited to, interest rate swaps, options, swaptions and lock agreements
to manage and mitigate interest rate risk exposure. For the three and six months
ended June 30, 2002 and 2001, the Company's existing interest rate derivative
instruments and related ineffectiveness were not material to its consolidated
results of operations, cash flows or financial position.
Foreign Currency (Fair Value or Cash Flow) Hedges. The Company is exposed to
foreign currency risk from investments in international affiliates and
businesses owned and operated in foreign countries. To mitigate risks associated
with foreign currency fluctuations, contracts may be denominated in or indexed
to the U.S. dollar and/or local inflation rates, or investments may be hedged
through debt denominated or issued in the foreign currency. The Company also
uses foreign currency derivatives to manage its risk related to foreign currency
fluctuations. As of June 30, 2002, an unrealized loss on foreign exchange
contracts of $40 million was included in the cumulative translation adjustment,
a separate component of OCI, as a hedge of our net investment in Canada. For the
three and six months ended June 30, 2001, the impact of the Company's foreign
currency derivative instruments was not material to its consolidated results of
operations, cash flows or financial position.
Credit Risk. The Company's principal customers for power and natural gas
marketing services are industrial end-users, marketers and utilities located
throughout the U.S., Canada, Asia Pacific, Europe and Latin America. The Company
has concentrations of receivables from natural gas and electric utilities and
their affiliates, as well as industrial customers throughout these regions.
These concentrations of customers may affect the Company's overall credit risk
in that some customers may be similarly affected by changes in economic,
regulatory or other factors. Where exposed to credit risk, the Company analyzes
the counterparties' financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of those limits on an
ongoing basis. The Company frequently uses master collateral agreements to
mitigate credit exposure. The collateral agreements provide for a counterparty
to post cash or letters of credit for exposure in excess of the established
threshold. The threshold amount represents an open credit limit, determined in
accordance with the corporate credit policy. The collateral agreement also
provides that the inability to post collateral is sufficient cause to terminate
a contract and liquidate all positions.
Despite the current challenges in the energy sector, management believes the
credit risk management process described above is operating effectively. As of
June 30, 2002, the Company held cash or letters of credit of $927 million to
secure future performance, and had deposited with counterparties $157 million of
such collateral to secure its obligations to provide future services. Collateral
amounts held or posted vary depending on the value of the underlying contracts
and cover trading, normal purchases and normal sales, and hedging contracts
outstanding. The Company may be required to return held collateral and post
additional collateral if price movements adversely impact the value of open
contracts or positions. The Company's and its counterparties' publicly disclosed
credit ratings impact the amounts of additional collateral to be posted.
12
The change in market value of New York Mercantile Exchange-traded futures and
options contracts requires daily cash settlement in margin accounts with
brokers. Financial derivatives are generally cash settled periodically
throughout the contract term. However, these transactions are also generally
subject to margin agreements with many of the Company's counterparties.
As of June 30, 2002, the Company had a pre-tax bad debt provision of $90 million
related to receivables for energy sales in California. Following the bankruptcy
of Enron Corporation, the Company terminated substantially all contracts with
Enron Corporation and its affiliated companies (collectively, Enron). As a
result, in 2001 the Company recorded, as a charge, a non-collateralized
accounting exposure of $19 million. The $19 million non-collateralized
accounting exposure was composed of charges of $12 million at DENA, $3 million
at International Energy, $3 million at Field Services and $1 million at Natural
Gas Transmission. These amounts were stated on a pre-tax basis as charges
against the reporting segment's earnings in 2001.
The Company's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$19 million. Any bankruptcy claims that exceed this amount would primarily
relate to termination and settlement rights under contracts and transactions
with Enron that would have been recognized in future periods, and not in the
historical periods covered by the financial statements to which the $19 million
charge relates.
Substantially all contracts with Enron were completed or terminated prior to
December 31, 2001. The Company has continuing contractual relationships with
certain Enron affiliates, which are not in bankruptcy. In Brazil, a power
purchase agreement between a Company affiliate, Companhia de Geracao de Energia
Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A
(Elektro), a distribution company approximately 100% owned by Enron, will expire
December 31, 2005. The contract was executed by the Company's predecessor in
interest in Paranapanema, and obligates Paranapanema to provide energy to
Elektro on an irrevocable basis for the contract period. In addition, a
purchase/sale agreement expiring September 1, 2005 between a Company affiliate
and Citrus Trading Corporation (Citrus), a 50/50 joint venture between Enron and
El Paso Corporation, continues to be in effect. The contract requires the
Company affiliate to provide natural gas to Citrus. Citrus has provided a letter
of credit in favor of the Company to cover its exposure.
13
5. Business Segments
The Company's reportable segments offer different products and services and are
managed separately as strategic business units. Beginning August 1, 2002, the
Company's North American trading and marketing functions currently in DENA,
including DETM and the Canadian trading operations, will be consolidated into
one group. Accounting policies for the Company's segments are the same as those
described in Note 2. Management evaluates segment performance based on earnings
before interest and taxes (EBIT) after deducting minority interests. The
following table shows how EBIT is calculated.
- -------------------------------------------------------------------------------------------------------------
Reconciliation of Operating Income to EBIT (in millions)
- -------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------
2002 2001 2002 2001
-------------------------------------------------------------
Operating income $599 $628 $ 961 $1,517
Plus: Other income and expenses 22 28 69 38
-------------------------------------------------------------
EBIT $621 $656 $1,030 $1,555
- -------------------------------------------------------------------------------------------------------------
EBIT is the primary performance measure used by management to evaluate segment
performance. As an indicator of the Company's operating performance or
liquidity, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with generally
accepted accounting principles. The Company's EBIT may not be comparable to a
similarly titled measure of another company.
14
In the accompanying table, EBIT includes the profit on intersegment sales at
prices representative of arms length party transactions. Capital and investment
expenditures are gross of cash received from acquisitions.
- -------------------------------------------------------------------------------------------------------------------------
Business Segment Data (in millions)
- -------------------------------------------------------------------------------------------------------------------------
Depreciation Capital and
Unaffiliated Intersegment Total and Investment
Revenues Revenues Revenues EBIT Amortization Expenditures
----------------------------------------------------------------------------------
Three Months Ended
June 30, 2002
Natural Gas Transmission $ 636 $ 42 $ 678 $ 312 $ 90 $ 253
Field Services 1,475 337 1,812 41 71 74
Duke Energy North America 9,307 40 9,347 124 39 785
International Energy 1,188 2 1,190 67 29 136
Other Energy Services 140 (25) 115 74 2 -
Duke Ventures 79 - 79 28 5 158
Other Operations/a/ - 91 91 (67) 2 (36)
Eliminations and
minority interests - (487) (487) 42 - -
---------------------------------------------------------------------------------
Total consolidated $ 12,825 $ - $ 12,825 $ 621 $ 238 $ 1,370
- -------------------------------------------------------------------------------------------------------------------------
Three Months Ended
June 30, 2001
Natural Gas Transmission $ 229 $ 35 $ 264 $ 142 $ 36 $ 207
Field Services 2,263 275 2,538 84 70 261
Duke Energy North America 9,856 128 9,984 290 20 830
International Energy 399 - 399 68 23 135
Other Energy Services 111 21 132 9 4 3
Duke Ventures 98 - 98 36 5 189
Other Operations/a/ - 31 31 3 9 29
Eliminations and
minority interests - (490) (490) 24 - -
---------------------------------------------------------------------------------
Total consolidated $ 12,956 $ - $ 12,956 $ 656 $ 167 $ 1,654
=========================================================================================================================
/a/ Other operations primarily includes certain unallocated corporate costs.
15
- -------------------------------------------------------------------------------------------------------------------
Business Segment Data (in millions)
- -------------------------------------------------------------------------------------------------------------------
Depreciation Capital and
Unaffiliated Intersegment Total and Investment
Revenues Revenues Revenues EBIT Amortization Expenditures
-----------------------------------------------------------------------------------
Six Months Ended
June 30, 2002
Natural Gas Transmission $ 1,092 $ 70 $ 1,162 $ 580 $ 144 $ 2,273
Field Services 2,834 544 3,378 76 145 184
Duke Energy North America 16,087 70 16,157 170 68 1,521
International Energy 2,173 3 2,176 134 52 217
Other Energy Services 210 41 251 72 3 1
Duke Ventures 118 - 118 34 9 283
Other Operations/a/ - 55 55 (92) 5 -
Eliminations and
minority interests - (783) (783) 56 - -
---------------------------------------------------------------------------------
Total consolidated $ 22,514 $ - $ 22,514 $ 1,030 $ 426 $ 4,479
- ------------------------------------------------------------------------------------------------------------------
Six Months Ended
June 30, 2001
Natural Gas Transmission $ 474 $ 72 546 $ 317 $ 71 $ 286
Field Services 4,887 1,049 5,936 207 138 307
Duke Energy North America 20,748 264 21,012 678 40 1,326
International Energy 897 4 901 144 48 158
Other Energy Services 215 35 250 13 7 8
Duke Ventures 135 - 135 43 9 363
Other Operations/a/ - 122 122 (2) 16 59
Eliminations and
minority interests - (1,546) (1,546) 155 - -
---------------------------------------------------------------------------------
Total consolidated $ 27,356 $ - $ 27,356 $ 1,555 $ 329 $ 2,507
==================================================================================================================
/a/ Other operations primarily includes certain unallocated corporate costs.
Segment assets in the accompanying table are net of intercompany advances,
intercompany notes receivable, intercompany current assets, intercompany
derivative assets and investments in subsidiaries.
- ------------------------------------------------------------------------------
Segment Assets (in millions)
- ------------------------------------------------------------------------------
June 30, December 31,
2002 2001
-----------------------------
Natural Gas Transmission $15,875 $ 5,027
Field Services 6,683 7,277
Duke Energy North America 19,514 14,005
International Energy 5,802 5,115
Other Energy Services 223 145
Duke Ventures 2,121 1,926
Other Operations, net of eliminations 1,044 1,795
----------------------------
Total consolidated $51,262 $35,290
=============================================================================
16
6. Debt
In February 2002, the Company, issued $500 million of 6.25% senior unsecured
bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due in 2032.
In addition, the Company, through a private placement transaction, issued $500
million of floating rate (based on the one-month London Interbank Offering Rate
(LIBOR) plus 0.65%) for senior unsecured bonds due in 2003. The proceeds from
these issuances were used for general corporate purposes.
In March 2002, a wholly owned subsidiary of the Company, Duke Australia Pipeline
Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with
various banks to fund its pipeline and power businesses in Australia. The
facility is split between a Company-guaranteed tranche and a non-recourse
project finance tranche that is secured by liens over existing Australian
pipeline assets. Proceeds from the project finance tranche were used to repay
inter-company loans.
In April 2002, the Company, through a private placement transaction, issued $100
million of floating rate (based on the one-month LIBOR plus 0.85%) senior
unsecured bonds due in 2004. The proceeds from this issuance were used to repay
commercial paper.
In July 2002, Texas Eastern Transmission, LP, a wholly owned subsidiary of the
Company, issued $300 million of 5.25% senior unsecured bonds due in 2007 and
$450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these
issuances were used for general corporate purposes, including the payment of
debt which matured in July 2002.
On March 14, 2002, the Company acquired Westcoast for approximately $8 billion,
including the assumption of $4.7 billion of debt. The assumed debt consists of
debt of Westcoast, Union Gas Limited (a wholly owned subsidiary of Westcoast)
and various project entities that are wholly owned or consolidated by the
Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with
maturity dates ranging from 2002 through 2031. (See Note 3.)
The Company's debt agreements contain various financial and other covenants.
Failure to comply with these covenants beyond applicable grace periods could
result in acceleration of due dates of the borrowings and/or termination of the
agreements. As of June 30, 2002, the Company is in compliance with these
covenants.
7. Commitments and Contingencies
Notice of Proposed Rulemaking (NOPR) on Standards of Conduct. In September 2001,
the FERC issued a NOPR announcing that it is considering new regulations
regarding standards of conduct that would apply uniformly to natural gas
pipelines that are currently subject to different gas standards. The proposed
standards would change how companies and their affiliates interact and share
information by broadening the definition of "affiliate" covered by the standards
of conduct. Various entities filed comments on the NOPR with the FERC, including
the Company's parent company, Duke Energy, which filed in December 2001. In
April 2002 the FERC Staff issued an analysis of the comments received by the
FERC. In several areas, the staff's analysis reflects important changes to the
NOPR. However, with regard to corporate governance, the staff's analysis
recommended adoption of an automatic imputation rule which could impact parent
company oversight of subsidiaries with transmission functions (pipeline and
storage functions). Duke Energy filed supplemental comments in June 2002. A
final rule is expected in the fall of 2002.
At its meeting in July 2002, the FERC issued its 600-page Standard Market Design
NOPR. The NOPR has major implications for the delivery of electric energy
throughout the U.S. Major elements of the FERC proposal include: (a) The use of
Network Access Service to replace the existing network and point-to-point
services. All customers, including load serving entities on behalf of bundled
retail load, would be required to take this service under a new pro forma
tariff. There would be no transmission rate pancaking among regions because
through-and-out charges would be eliminated. (b) By July 31, 2003, vertically
integrated utilities would be required to retain Independent Transmission
Providers to administer the new tariff and
17
functionally operate transmission systems. (c) Congestion management would be
provided through the use of Locational Marginal Pricing, a transparent method of
pricing transmission congestion costs as a component of energy transactions in a
given market. Market participants would be allocated or could purchase
Congestion Revenue Rights to manage congestion risk. (d) The formation of
Regional State Advisory Committees and other regional entities to coordinate the
planning, certification and siting of new transmission facilities in cooperation
with states. Some of these features are likely to be highly contested by the
various stakeholders.
The Company has initiated a detailed review of the NOPR. Initial comments on the
NOPR are due to the FERC by October 15, 2002. The FERC has indicated that it
intends to issue a final rule by February 2003. While the NOPR is complex, and
remains under review, the early indications are that it appears unlikely to
materially impact the consolidated financial statements of the Company.
Litigation and Contingencies. California Matters. Duke Energy, some of the
Company's subsidiaries, and three current or former executives have been named
as defendants, among numerous other corporate and individual defendants, in one
or more of a total of 14 lawsuits, filed in California on behalf of purchasers
of electricity in the State of California, with one suit filed on behalf of a
Washington State electricity purchaser. Most of these lawsuits seek class action
certification and damages, and other relief, as a result of the defendants'
alleged unlawful manipulation of the California wholesale electricity markets.
These lawsuits generally allege that the defendants manipulated the wholesale
electricity markets in violation of state laws against unfair and unlawful
business practices and, in some suits, in violation of state antitrust laws.
Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The
lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained
revenues for sales of electricity and, in some lawsuits, an award of treble
damages for alleged violations of state antitrust laws.
The first six of these lawsuits were filed in late 2000 through mid-2001 and
have been consolidated before a single judge in San Diego. The plaintiffs in the
six lawsuits filed a joint Master Amended Complaint in March 2002, which adds
additional defendants. The claims against the defendants are similar to those in
the original complaints. In April 2002, some defendants, including Duke Energy,
filed cross-complaints against various market participants not named as
defendants in the plaintiffs' original and amended complaints.
Eight of these 14 suits were filed in mid-2002, seven by plaintiffs in
California and one by a plaintiff in the State of Washington. These eight suits
are being considered for consolidation with the six previously filed lawsuits.
These matters are in their earliest stages. The Company is currently evaluating
these claims and intends to vigorously defend itself.
The Company and its subsidiaries are involved in other legal and regulatory
proceedings and investigations related to activities in California. These other
activities were disclosed in the Company's Form 10-K for the year ended December
31, 2001, and there have been no new material developments in relation to these
issues.
Trading Matters. Since April 2002, 16 shareholder class action lawsuits have
been filed against Duke Energy: 13 in the United States District Court for the
Southern District of New York and three in the United States District Court for
the Western District of North Carolina. Some of the lawsuits also name as
co-defendants some Duke Energy executives, Duke Energy's independent external
auditor and various investment banking firms. In addition, Duke Energy has
received a shareholder's derivative notice demanding that it commence litigation
against named executives and directors of Duke Energy for alleged breaches of
fiduciary duties and insider trading. Duke Energy has also received a second
similar shareholder's derivative notice demanding litigation against named
executives and directors for alleged failure to prevent damages caused to Duke
Energy arising from trades involving simultaneous purchases and sales of power
and gas at the same price ("round-trip" trading). Duke Energy's response date to
the first derivative demand has been extended to after the first of the year
2003. Duke Energy is negotiating a similar agreement with respect to the second
derivative demand.
18
The class actions and the threatened shareholder derivative claims arise out of
allegations that Duke Energy improperly engaged in the so-called "round trip"
trades which resulted in an alleged overstatement of revenues over a three-year
period of approximately $1 billion. The plaintiffs seek recovery of an unstated
amount of compensatory damages, attorneys' fees and costs for alleged violations
of securities laws. In one of the lawsuits, the plaintiffs assert a common law
fraud claim and seek, in addition to compensatory damages, disgorgement and
punitive damages. These matters are in their earliest stages. Duke Energy is
currently evaluating these claims and intends to vigorously defend itself.
In 2002, Duke Energy received and responded to information requests from the
FERC, an informal request for information from the Securities and Exchange
Commission (SEC), and a subpoena from the Commodity Futures Trading Commission.
Duke Energy also received and will respond to a grand jury subpoena issued by
the U.S. Attorney's office in Houston. All information requests and subpoenas
seek documents and information related to trading activities, including
so-called "round-trip" trading. Duke Energy is cooperating with the respective
governmental agencies on each of these inquiries.
Duke Energy submitted a final report to the SEC based on a review of
approximately 750,000 trades made by various Duke Energy subsidiaries between
January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review
of trading, accounting, and other records, with the assistance of Duke Energy
senior legal, corporate risk management and accounting personnel. Duke Energy
identified 28 "round-trip" transactions done for the apparent purpose of
increasing volumes on the Intercontinental Exchange and 61 "round-trip"
transactions done at the direction of one of Duke Energy's traders that did not
have a legitimate business purpose and were contrary to corporate policy. Duke
Energy determined that the financial impact of these "round trip" transactions
was not material.
As a result of the trading review, Duke Energy has terminated two employees and
put in place additional risk management procedures to improve and strengthen the
oversight and controls of its trading operations. Duke Energy has also
reconfirmed to employees that engaging in simultaneous or prearranged
transactions that lack a legitimate business purpose, or any trading activities
that lack a legitimate business purpose, is against company policy. Beginning
August 1, 2002, North American trading and marketing functions currently in
DENA, including DETM and the Canadian trading operations, will be consolidated
into one group. This organization will develop consistent policies, practices
and systems for the entire trading and marketing operation and implement better
control systems to improve monitoring and reporting capabilities.
Price Mitigation Matters. In November 2001, Nevada Power Company and Sierra
Pacific Power Company (collectively, the Power Companies) filed a complaint with
the FERC against DETM. The complaint requests the FERC to mitigate prices in
sales contracts between the Company and Nevada Power, and the Company and Sierra
Pacific that were entered into between December 7, 2000 and June 20, 2001. The
Power Companies allege that the contract prices are unjust and unreasonable
because they were entered into during a period that the FERC determined the
California market to be dysfunctional and uncompetitive, and that the California
market influenced the contract prices. In April 2002, the FERC issued an order
which provides for an evidentiary hearing, establishes refund dates, and
requires the parties to participate in settlement negotiations. The parties have
reached a settlement pursuant to which the Power Companies dismissed their
complaint against DETM in June 2002. As part of this settlement, the Company has
agreed to supply up to 1,000 megawatts of electricity per hour, as well as
natural gas, to the Power Companies to fulfill customers' power requirements
during the peak summer period. In addition, the Company will further provide
real-time purchases and sales of power between June 15 and December 31, 2002,
under mutually agreeable terms to assist the Power Companies in balancing
electricity demands. DETM is an intervener in cases against other sellers to
these two utilities, but is no longer a respondent in this proceeding.
19
In July 2002, the Sacramento Municipal Utility District (SMUD) filed a complaint
with the FERC against DETM requesting that the FERC mitigate unjust and
unreasonable prices in four mid- and long-term sales contracts between DETM and
SMUD entered into between February 7, 2001 and March 26, 2001. SMUD, alleging
that DETM had the ability to exercise market power, claims that the contract
prices are unjust and unreasonable because they were entered into during a
period that the FERC determined the western markets to be dysfunctional and
uncompetitive and that the western markets influenced their price. In support of
its request to mitigate the contract price, SMUD relies on the fact that the
contract prices are higher than prices in the western U.S. following
implementation of the FERC's June 2001 price mitigation plan. SMUD requests the
FERC to set "just and reasonable" contract rates and to promptly set a refund
effective date.
The Company and its subsidiaries are involved in other legal, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding performance, contracts and other matters arising in the
ordinary course of business, some of which involve substantial amounts.
Management believes that the final disposition of these proceedings will have no
material adverse effect on consolidated results of operations, cash flows or
financial position.
8. Subsequent Events
Westcoast has entered into an agreement to sell its 60% interest in the
Frederickson Power Project for cash proceeds of approximately $100 million. The
Company expects to record a pre-tax gain of approximately $2 million upon
completion of the transaction, which is subject to regulatory approvals and is
expected to finalized by the end of the third quarter of 2002.
In July 2002, Duke Energy International LLC acquired a 103 megawatt gas-fired
combined heat and power plant located in northwest France for approximately $69
million.
In July 2002, Standard & Poor's (S&P) placed its ratings for the Company and
some of its subsidiaries on CreditWatch with negative implications. Moody's
Investors Service and Fitch Ratings changed their ratings outlook for the
Company and some of its subsidiaries from Stable to Negative. In August 2002,
the Company was informally advised by S&P that its credit ratings described
above would be lowered one rating level and S&P would change its negative
outlook to stable. The Company was also informally advised that S&P's commercial
paper ratings would remain at current levels. The Company does not anticipate
these actions to have a material adverse impact on its financial statements.
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
Introduction
Duke Capital Corporation (collectively with its subsidiaries, the Company), is a
wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as
the parent of some of Duke Energy's non-utility and other operations. The
Company provides financing and credit enhancement services for its subsidiaries
and conducts operations through its six business segments. See Note 1 to the
Consolidated Financial Statements for descriptions of the Company's business
segments.
Management's Discussion and Analysis should be read in conjunction with the
Consolidated Financial Statements.
RESULTS OF OPERATIONS
For the three months ended June 30, 2002, net income was $239 million, compared
to $314 million for 2001. The decrease was due primarily to a $67 million
increase in interest expense, due primarily to the debt assumed in the
acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002. (See Note 3 to
the Consolidated Financial Statements.) The comparative decrease also resulted
from an $18 million increase in minority interest expense, as discussed in the
following sections, and from a 5.3% decrease in earnings before interest and
taxes (EBIT), as described below.
20
For the six months ended June 30, 2002, net income was $413 million, compared to
$633 million for 2001. The decrease was due primarily to a 33.8% decrease in
earnings before interest and taxes (EBIT), as described below, and a $53 million
increase in interest expense. These changes were partially offset by the prior
year's one-time net-of-tax charge of $69 million. This one-time charge was the
cumulative effect of change in accounting principle for the January 1, 2001
adoption of Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities." Also offsetting
the changes in EBIT and interest expense was a $110 million decrease in minority
interest expense, as discussed in the following sections.
Operating income decreased $29 million to $599 million for the quarter, and
decreased $556 million to $961 million for the six months ended June 30, 2002.
EBIT decreased $35 million to $621 million for the quarter, and decreased $525
million to $1,030 million for the six months ended June 30, 2002. Operating
income and EBIT are affected by the same fluctuations for Duke Energy and each
of its business segments.
The following table shows the components of EBIT and reconciles EBIT to net
income.
=============================================================================================================
Reconciliation of Operating Income to Net Income (in millions)
- -------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------
2002 2001 2002 2001
------------------------------------------------------------------
Operating income $ 599 $ 628 $ 961 $ 1,517
Other income and expenses 22 28 69 38
------------------------------------------------------------------
EBIT 621 656 1,030 1,555
Interest expense 207 140 338 285
Minority interest expense 52 34 73 183
------------------------------------------------------------------
Earnings before income taxes 362 482 619 1,087
Income taxes 123 168 206 385
------------------------------------------------------------------
Income before cumulative
effect of change in accounting
principle 239 314 413 702
Cumulative effect of change in
accounting principle, net of tax - - - (69)
------------------------------------------------------------------
Net income $ 239 $ 314 $ 413 $ 633
=============================================================================================================
EBIT is the primary performance measure used by management to evaluate segment
performance. As an indicator of the Company's operating performance or
liquidity, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with generally
accepted accounting principles. The Company's EBIT may not be comparable to a
similarly titled measure of another company.
21
Beginning August 1, 2002, Duke Energy's North American trading and marketing
functions currently in Duke Energy North America (DENA), including Duke Energy
Trading and Marketing. LLC (DETM) and the Canadian trading operations, will be
consolidated into one group. Business segment EBIT is summarized in the
following table, and detailed discussions follow.
=============================================================================================================
EBIT by Business Segment (in millions)
- -------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------
Natural Gas Transmission $ 312 $ 142 $ 580 $ 317
Field Services 41 84 76 207
Duke Energy North America 124 290 170 678
International Energy 67 68 134 144
Other Energy Services 74 9 72 13
Duke Ventures 28 36 34 43
Other Operations (67) 3 (92) (2)
EBIT attributable to minority interests 42 24 56 155
--------------------------------------------------------------
Consolidated EBIT $ 621 $ 656 $ 1,030 $ 1,555
=============================================================================================================
Other Operations primarily includes certain unallocated corporate costs and
elimination of intersegment profits. The amounts discussed below include
intercompany transactions that are eliminated in the Consolidated Financial
Statements.
Natural Gas Transmission
- --------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------
(in millions, except where noted) 2002 2001 2002 2001
- --------------------------------------------------------------------------------
Operating revenues $678 $264 $1,162 $546
Operating expenses 361 125 579 232
-------------------------------------------
Operating income 317 139 583 314
Other income, net of expenses 4 3 9 3
Minority interest expense 9 - 12 -
-------------------------------------------
EBIT $312 $142 $ 580 $317
===========================================
Proportional throughput, TBtu /a/ 702 368 1,372 916
- --------------------------------------------------------------------------------
/a/ Trillion British thermal units
For the quarter ended June 30, 2002, EBIT for Natural Gas Transmission increased
$170 million, and for the six months, EBIT increased $263 million compared to
the same periods in 2001. The increase for both periods primarily resulted from
earnings from the natural gas transmission and distribution assets acquired as a
part of the acquisition of Westcoast in March 2002. (See Note 3 to the
Consolidated Financial Statements.) Earnings for Westcoast were $109 million for
the quarter and $172 million for the six months. Earnings associated with market
expansion projects, including the Gulfstream Natural Gas System, a 581-mile
pipeline system, 50% owned by Duke Energy that went into service in May 2002,
also contributed to both periods. These earnings included a $27 million
construction fee from an affiliate related to the successful completion of the
Gulfstream Natural Gas System.
Also contributing to the six-month period was a $14 million gain on the sale of
a portion of Natural Gas Transmission's limited partnership interest in Northern
Border Partners, LP, which owns a general partnership interest in Northern
Border Pipeline Company.
22
Field Services
- --------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------------
(in millions, except where noted) 2002 2001 2002 2001
- --------------------------------------------------------------------------------------
Operating revenues $ 1,812 $2,538 $3,378 $5,936
Operating expenses 1,758 2,406 3,281 5,625
--------------------------------------------
Operating income 54 132 97 311
Minority interest expense 13 48 21 104
--------------------------------------------
EBIT $ 41 $ 84 $ 76 $ 207
============================================
Natural gas gathered and
processed/transported, TBtu/d /a/ 8.4 8.5 8.4 8.4
Natural gas liquid (NGL) production,
MBbl/d /b/ 392.0 406.7 390.4 386.9
Natural gas marketed, TBtu/d 1.6 1.6 1.6 1.6
Average natural gas price per MMBtu /c/ $ 3.40 $ 4.67 $ 2.86 $ 5.88
Average NGL price per gallon /d/ $ 0.37 $ 0.48 $ 0.34 $ 0.54
- --------------------------------------------------------------------------------------
/a/ Trillion British thermal units per day
/b/ Thousand barrels per day
/c/ Million British thermal units
/d/ Does not reflect results of commodity hedges
EBIT for Field Services decreased $43 million for the quarter and $131 million
for the six months ended June 30, 2002 compared to the same periods in 2001, due
primarily to increases in operating and maintenance costs and decreases in
commodity prices. The decrease in commodity prices was driven by decreases in
average NGL prices of $0.11 per gallon for the quarter and $0.20 per gallon for
the six months, partially offset by decreases in the average natural gas prices
of $1.27 per MMBtu for the quarter and $3.02 per MMBtu for the six months.
During the quarter, Field Services also recorded additional charges for an
increase in its provision for imbalances with customers and suppliers, and a
reduction to its storage inventory resulting from a study completed on one of
Field Services' sites to determine the current capacity levels. The net EBIT
impact, after minority interest, of these charges was $13 million.
Subsequent to earnings being reported to the Company for the quarter ended June
30, 2002, Field Services determined and recorded various adjustments which
reduced reported EBIT for June 2002 based on new information and analysis. These
adjustments are not material to the results of the Company and they are not
reflected in the Company's second quarter 2002 financial statements.
23
Duke Energy North America
- ----------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------------------
(in millions, except where noted) 2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------
Operating revenues $ 9,347 $ 9,984 $ 16,157 $ 21,012
Operating expenses 9,213 9,738 15,977 20,300
--------------------------------------------------
Operating income 134 246 180 712
Other income, net of expenses 4 14 3 4
Minority interest expense (benefit) 14 (30) 13 38
--------------------------------------------------
EBIT $ 124 $ 290 $ 170 $ 678
==================================================
Natural gas marketed, TBtu/d 15.3 11.2 14.2 12.3
Electricity marketed and traded, GWh 95,385 66,225 201,601 110,842
Proportional megawatt capacity in
operation 12,671 6,846
Proportional megawatt capacity owned /a/ 18,671 13,231
- ----------------------------------------------------------------------------------------------
/a/ Includes under construction or under contract at period end
For the quarter ended June 30, 2002, DENA's EBIT decreased $166 million and for
the six months, it decreased $508 million, as compared to the same periods in
2001. An increase of 85.1% in the proportional megawatt capacity of generation
assets in operation and increases in the marketing and trading of electricity
volumes of 44.0% for the quarter and 81.9% for the six months were significantly
offset by decreased origination activities and trading margins. Last year's
results were driven by unusually high natural gas and power prices, and
volatility levels (measures of the fluctuation in the prices of
energy contracts), especially in the western U.S. The second quarter of 2001
also included significant net gains from the sale of interests in generating
facilities as a result of DENA executing its portfolio management strategy.
Partially offsetting these decreases were lower variable compensation costs
related to the trading activities. Results for the second quarter of 2002 also
include a $14 million reduction of the fair value of the mark-to-market
portfolio as a result of applying improved and standardized valuation modeling
techniques for all North American regions.
As a result of the Company's findings related to the Securities and Exchange
Commission's (SEC) informal inquiry on electricity trades involving simultaneous
purchases and sales of power at the same price ("round trip" trades), DENA
recorded adjustments which reduced its EBIT by $17 million during the quarter
ended June 30, 2002. An additional $2 million charge was recorded in other Duke
Energy business segments related to these findings. (See Current Issues -
Litigation and Contingencies, Trading Matters for additional information.)
For the prior year quarter, losses at DETM resulted in a minority interest
benefit, whereas increased earnings at DETM for the current year quarter
resulted in minority interest expense. When compared to the prior year, minority
interest expense for the six months decreased $25 million due to changes in the
ownership percentage of DENA's waste-to-energy plants and decreased earnings at
DETM.
In June 2002, the Financial Accounting Standard's Board's (FASB) Emerging Issues
Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Recognition
and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," and EITF No. 00-17, "Measuring the Fair Value of
Energy-Related Contracts in Applying Issue No. 98-10." The EITF concluded that,
effective for periods ending after July 15, 2002, mark-to-market gains and
losses on energy trading contracts (including those to be physically settled)
must be shown on a net basis in the Consolidated Statements of Income.
Comparative financial statements for prior periods must be reclassified to
reflect presentation on a net basis. Also, companies must disclose volumes of
physically settled energy trading contracts. The Company is evaluating the
impact of this new consensus on the presentation of its Consolidated Statements
of Income, but believes it will have a material impact on total revenues and
expenses. The partial consensus will have no impact on net income.
24
International Energy
- ----------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------
(in millions, except where noted) 2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------
Operating revenues $ 1,190 $ 399 $ 2,176 $ 901
Operating expenses 1,125 334 2,052 762
----------------------------------------------------
Operating income 65 65 124 139
Other income, net of expenses 8 9 21 18
Minority interest expense 6 6 11 13
----------------------------------------------------
EBIT $ 67 $ 68 $ 134 $ 144
====================================================
Sales, GWh /a/ 5,014 4,596 9,946 9,037
Natural gas marketed, TBtu/d 3.7 2.5 3.4 2.4
Electricity marketed and traded, GWh 24,740 1,632 41,872 3,391
Proportional megawatt capacity in operation 4,971 4,241
Proportional megawatt capacity owned /b/ 5,746 4,844
Proportional maximum pipeline capacity in
operation /b/, MMcf/d /c/ 363 255
Proportional maximum pipeline capacity
owned /b/, MMcf/d 363 363
- ----------------------------------------------------------------------------------------------------
/a/ GWh sold by the operating assets to consumers, industrial users, etc.
/b/ Includes under construction or under contract at period end
/c/ Million cubic feet per day
International Energy's EBIT decreased $1 million for the quarter and $10 million
for the six months ended June 30, 2002 compared to the same periods in 2001. The
decreases were due primarily to decreased earnings from the European operations,
which were affected by lower trading margins and lower product prices. Partially
offsetting the decrease from the European operations, were increased earnings
from the Latin American and Asia Pacific operations, which included additions to
International Energy's portfolio of assets from the Company's acquisition of
Westcoast. The increases in International Energy's operating revenues and
expenses for 2002 are due primarily to its increased trading and marketing
activities in Europe.
Other Energy Services
- ---------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
-----------------------------------------------------
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------
Operating revenues $115 $132 $251 $250
Operating expenses 41 123 179 237
-----------------------------------------------------
EBIT $ 74 $ 9 $ 72 $ 13
=============================================================================================
For the quarter ended June 30, 2002, EBIT for Other Energy Services increased
$65 million and for the six months, it increased $59 million, compared to the
same periods in 2001. The increases for the quarter and six months were due
primarily to increased earnings at Duke/Fluor Daniel (D/FD), as a result of D/FD
completing a number of energy plants. Most of the plants completed during the
quarter were constructed for DENA and therefore the related intercompany profit
has been eliminated within the Other Operations segment.
25
On April 30, 2002, the Company completed the sale of Duke Engineering &
Services, Inc. to Framatome ANP, Inc. and, on May 1, 2002, the Company completed
the sale of DukeSolutions, Inc. to Ameresco, Inc. (See Note 3 to the
Consolidated Financial Statements). The combined result of these sales was a net
gain of $14 million for the quarter and a net loss of $1 million for the six
months. The difference between the quarterly and the six month results is due to
a $15 million reserve that was established in the first quarter of 2002 for the
expected loss associated with the sale of DukeSolutions, Inc.
Duke Ventures
- ---------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------
Operating revenues $ 79 $98 $118 $135
Operating expenses 51 62 85 92
--------------------------------------------------------
Operating income 28 36 33 43
Minority interest benefit - - (1) -
-------------------------------------------------------
EBIT $ 28 $36 $ 34 $ 43
===================================================================================================
EBIT for Duke Ventures decreased $8 million for the quarter and $9 million for
the six months ended June 30, 2002 compared to the same periods in 2001, due
primarily to decreased earnings at Crescent Resources, LLC, due primarily to
decreased commercial project sales and rents.
Other Operations
For the quarter ended June 30, 2002, Other Operations' EBIT decreased $70
million and for the six months, it decreased $90 million, compared to the same
periods in 2001. The decreases are due primarily to increased intercompany
profits between the Company's segments which are eliminated within the Other
Operations Segment. These intercompany profits include earnings at D/FD for
energy plants it has completed for DENA.
Other Impacts on Net Income
For the quarter ended June 30, 2002, interest expense increased $67 million and
for the six months ended June 30, 2002, interest expense increased $53 million
compared to the same periods in 2001. The increases are primarily due to higher
debt balances resulting from debt assumed in the acquisition of Westcoast.
Minority interest expense increased $18 million for the quarter but decreased
$110 million for the six months ended June 30, 2002 compared to the same periods
in 2001. Minority interest expense includes expense related to regular
distributions on preferred securities of the Company and its subsidiaries. This
expense decreased $6 million for the quarter and $17 million for the six months
ended June 30, 2002 due primarily to lower distributions related to Catawba
River Associates, LLC (Catawba). Catawba is a fully consolidated financing
entity formed by the Company in September 2000 and is managed by a Company
subsidiary.
Minority interest expense as shown and discussed in the preceding business
segment EBIT discussions includes only minority interest expense related to EBIT
of the Company's joint ventures. It does not include minority interest expense
related to interest and taxes of the joint ventures. Total minority interest
expense related to the joint ventures (including the portion related to interest
and taxes) increased $24 million for the quarter but decreased $93 million for
the six month period. For the quarter, the change was driven by increased income
at DETM, DENA's joint venture with Exxon Mobil Corporation, partially offset by
decreased income from the Company's joint venture with Phillips Petroleum. For
the six months, the change was driven by decreased income from Field Services
joint venture, changes in the ownership percentage of DENA's waste-to-energy
plants and decreased earnings at DETM.
26
During the first quarter of 2001, the Company recorded a one time net-of-tax
charge of $69 million related to the cumulative effect of change in accounting
principle for the January 1, 2001 adoption of SFAS No. 133. This charge related
to contracts that either did not meet the definition of a derivative under
previous accounting guidance or do not qualify as hedges under new accounting
requirements.
LIQUIDITY AND CAPITAL RESOURCES
Operating Cash Flows
For the six months ended June 30, 2002, net cash provided by operations
decreased $310 million when compared to the same period in 2001. The decrease is
due primarily to cash posted by counterparties. Counterparties may be required
to post collateral in cash or letters of credit if price moves benefit the
Company. This mechanism gives the Company use of those funds on a short-term
basis. Conversely, negative price impacts reduce earnings and may require the
Company to post collateral with its counterparties. Cash collateral posted by
the Company is included in Other Current Assets and cash collateral collected by
the Company is included in Other Current Liabilities on the Consolidated Balance
Sheets. In 2002, the Company held less cash posted by counterparties (primarily
due to cash posted by Enron Corporation in 2001). In addition, during the first
six months of 2001, the Company reduced the amount of cash it had posted with
counterparties from December 31, 2000. Partially offsetting these reductions
were increased amounts of net payables related to higher gas prices and contract
volumes and the net unrealized mark-to-market and hedging transactions resulting
from increased cash earnings in 2002 versus 2001. As a result of the increased
volatility and higher prices in the western U.S. for power in 2001, the Company
experienced a higher level of mark-to-market appreciation as compared to 2002.
Investing Cash Flows
Net cash used in investing activities increased $2,103 million for the six
months ended June 30, 2002 when compared to the same period in 2001, primarily
due to the acquisition of Westcoast for $1,690 million in cash, net of cash
acquired (see Note 3 to the Consolidated Financial Statements). Capital and
investment expenditures increased $210 million in 2002 compared to 2001. The
increase reflects additional expansion and development expenditures (especially
related to DENA's generating facilities), refurbishment and upgrades to existing
assets and minor acquisitions of businesses and assets.
Capital spending for 2002 is expected to be approximately $5,200 million,
excluding the acquisition of Westcoast. For 2003 and 2004, the Company estimates
capital spending to be approximately $2,600 million to $3,400 million.
Financing Cash Flows
The Company's future cash requirements are expected to be funded largely by cash
from operations, including the sale of assets. In addition, the Company expects
to access the capital markets as needed. Ability to access the capital markets
is dependent upon market opportunities presented. Management believes the
Company has adequate financial flexibility and resources to meet its future
needs.
In February 2002, the Company issued $500 million of 6.25% senior unsecured
bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due in 2032.
In addition, the Company, through a private placement transaction, issued $500
million of floating rate (based on the one-month London Interbank Offered Rate
(LIBOR) plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these
issuances were used for general corporate purposes.
27
In March 2002, a wholly owned subsidiary of the Company, Duke Australia Pipeline
Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with
various banks to fund its pipeline and power businesses in Australia. The
facility is split between a Company-guaranteed tranche and a non-recourse
project finance tranche that is secured by liens over existing Australian
pipeline assets. Proceeds from the project finance tranche were used to repay
inter-company loans.
In April 2002, the Company, through a private placement transaction, issued $100
million of floating rate (based on the one-month LIBOR plus 0.85%) senior
unsecured bonds due in 2004. The proceeds from this issuance were used to repay
commercial paper.
In July 2002, Texas Eastern Transmission, LP, a wholly owned subsidiary of the
Company, issued $300 million of 5.25% senior unsecured bonds due in 2007 and
$450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these
issuances were used for general corporate purposes, including the repayment of
debt which matured in July 2002.
On March 14, 2002, the Company acquired Westcoast for approximately $8 billion,
including the assumption of $4.7 billion of debt. The assumed debt consists of
debt of Westcoast, Union Gas Limited (a wholly-owned subsidiary of Westcoast)
and various project entities that are wholly owned or consolidated by the
Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with
maturity dates ranging from 2002 through 2031. In addition to the debt assumed,
Westcoast and Union Gas Limited have operating credit facilities of 600 million
Canadian dollars and 715 million Canadian dollars, respectively. Borrowings
under each of these facilities are subject to and dependent upon the senior
unsecured ratings of Westcoast (currently rated A (low) for Dominion Bond Rating
Service (DBRS) and A+ for Standard & Poor's) and Union Gas Limited (currently
rated A for DBRS and A+ for Standard & Poor's). For the Westcoast credit
facility, no material adverse change can be declared if Westcoast maintains a
rating of BBB(low) or greater at DBRS or a BBB- or greater at Standard & Poor's.
For Union Gas Limited's facility, no material adverse change can be declared if
Union Gas Limited maintains a rating of BBB or greater by either DBRS or
Standard & Poor's. For both facilities, any outstanding debt would not become
due and payable as a result of a change in ratings.
Westcoast, headquartered in Vancouver, British Columbia, is a North American
energy company with interests in natural gas gathering, processing,
transmission, storage and distribution, as well as power generation and
international energy businesses. In the transaction, a Company subsidiary
acquired all of the outstanding common shares of Westcoast in exchange for
approximately 49.9 million shares of Duke Energy common stock (including
exchangeable shares of a Duke Energy Canadian subsidiary that are substantially
equivalent to and exchangeable on a one-for-one basis for Duke Energy common
stock), and approximately $1.8 billion in cash. Under prorating provisions of
the acquisition agreement that ensured that approximately 50% of the total
consideration was paid in cash and 50% in stock, each common share of Westcoast
entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a
share of Duke Energy common stock or of an exchangeable share of a Duke Energy
Canadian subsidiary, or a combination thereof. The cash portion of the
consideration was funded with the proceeds from the issuance of $750 million in
mandatory convertible securities in November 2001 along with incremental
commercial paper. Duke Energy plans to retire the commercial paper later in 2002
and replace it with permanent capital in the form of equity or equity linked
securities. The timing for the equity or equity linked securities will be
dependent on the market opportunities presented. The Westcoast acquisition was
accounted for using the purchase method of accounting, and goodwill totaling
approximately $2.5 billion was recorded in the transaction.
28
Under its commercial paper and extendible commercial notes (ECNs) programs, the
Company had the ability, subject to market conditions, to borrow up to $5,348
million as of June 30, 2002 compared with $3,608 million as of December 31,
2001. These programs do not have termination dates. The following table
summarizes the commercial paper and ECN capacity as of June 30, 2002.
- ---------------------------------------------------------------------------------
Duke Capital Duke Energy Duke Energy
(in millions) Corporation Field Services International Westcoast Total
- ---------------------------------------------------------------------------------
Commercial Paper $2,550 $650 $282 $866/a/ $4,348
ECNs 1,000 - - - 1,000
--------------------------------------------------------------
Total $3,550 $650 $282 $866 $5,348
=================================================================================
/a/ As of July 19, 2002, the Union Gas Limited commercial paper program was
renegotiated from $471 million to $395 million.
The total amount of the Company's bank credit facilities was $5,439 million as
of June 30, 2002 compared with $3,406 million as of December 31, 2001. Some of
the credit facilities support the issuance of commercial paper and as a result,
the issuance of commercial paper reduces the amount available under these credit
facilities. As of June 30, 2002, $2,991 million was outstanding in the form of
commercial paper and ECNs, and $44 million of borrowings were outstanding under
the bank credit facilities. The credit facilities expire from August 2002 to
2005 and are not subject to minimum cash requirements.
As of June 30, 2002, the Company and its subsidiaries had effective SEC shelf
registrations for up to $1,750 million in gross proceeds from debt and other
securities. Subsequent to June 30, 2002, these shelf registrations have been
reduced by $750 million for the senior unsecured bonds issued in July 2002 by
Texas Eastern Transmission, LP. In addition, Westcoast and its subsidiaries had
$626 million of unused Canadian debt capacity as of June 30, 2002.
In July 2002, Standard & Poor's placed its ratings for the Company and some of
its other subsidiaries on CreditWatch with negative implications. Moody's
Investors Service and Fitch Ratings changed their ratings outlooks for the
Company and its subsidiaries from Stable to Negative. In August 2002, the
Company was informally advised by Standard & Poor's that its credit ratings
described above would be lowered one rating level and Standard & Poor's would
change its negative outlook to stable. The Company was also informally advised
that Standard & Poor's commercial paper ratings would remain at current levels.
The Company does not anticipate these actions to have a material adverse impact
on its financial results.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk and Accounting Policies
The Company is exposed to market risks associated with commodity prices, credit
exposure, interest rates, equity prices and foreign currency exchange rates.
Management has established comprehensive risk management policies to monitor and
manage these market risks. Duke Energy's Policy Committee is responsible for the
overall approval of market risk management policies and the delegation of
approval and authorization levels. The Policy Committee is composed of senior
executives who receive periodic updates from the Chief Risk Officer (CRO) on
market risk positions, corporate exposures, credit exposures and overall risk
management activities. The CRO is responsible for the overall management of
credit risk and commodity price risk, including monitoring exposure limits.
Mark-to-Market Accounting (MTM accounting). Under the MTM accounting method, an
asset or liability is recognized at fair value and the change in the fair value
of that asset or liability is recognized in earnings during the current period.
This accounting method has been used by other industries for many years, and in
1998 the EITF issued guidance that required MTM accounting for energy trading
contracts. MTM accounting reports contracts at their "fair value," (the value a
willing third party would pay for the particular contract at the time a
valuation is made).
29
When available, quoted market prices are used to record a contract's fair value.
However, market values for energy trading contracts may not be readily
determinable because the duration of the contracts exceeds the liquid activity
in a particular market. If no active trading market exists for a commodity or
for a contract's duration, holders of these contracts must calculate fair value
using pricing models or matrix pricing based on contracts with similar terms and
risks. This is validated by an internal group independent of the Company's
trading area. Holders of thinly traded securities or investments (mutual funds,
for example) use similar techniques to price such holdings. Correlation and
volatility are two significant factors used in the computation of fair values.
The Company validates its internally developed fair values by comparing
locations/durations that are highly correlated, using market intelligence and
mathematical extrapolation techniques. While the Company uses industry best
practices to develop its pricing models, changes in the Company's pricing
methodologies or the underlying assumptions could result in significantly
different fair values, income recognition and realization in future periods.
Hedge Accounting. Hedging typically refers to the mechanism that the Company
uses to mitigate the impact of volatility associated with price fluctuations.
Hedge accounting treatment is used when the Company contracts to buy or sell a
commodity such as natural gas or electricity at a fixed price for future
delivery corresponding with anticipated physical sales or purchases of natural
gas and power (cash flow hedge). In addition, hedge accounting treatment is used
when the Company holds firm commitments or asset positions, and enters into
transactions that "hedge" the risk that the price of natural gas or power may
change between the contract's inception and the physical delivery date of the
commodity ultimately affecting the underlying value of the firm commitment or
position (fair value hedge). The majority of the Company's hedging transactions
are used to protect the value of future cash flows related to its physical
assets. To the extent the hedge is effective, the Company recognizes in earnings
the value of the contract when the commodity is purchased or sold, or the hedged
transaction occurs or settles.
Normal Purchases and Normal Sales, Special Exemption. A unique characteristic of
the electric power industry is that electricity cannot be readily stored in
significant quantities. As a result, some of the contracts to buy and sell
electricity allow the buyer some flexibility in determining when to take
electricity and in what quantity to match fluctuating demand. These contracts
would normally meet the definition of a derivative requiring MTM or hedge
accounting. However, because electricity cannot be readily stored in significant
quantities and an entity engaged in selling electricity is obligated to maintain
sufficient capacity to meet the electricity needs of its customer base, some
electricity contracts with optionality features may qualify for the normal
purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and
Derivative Implementation Group (DIG) Issue No. C15, "Scope Exceptions: Normal
Purchases and Normal Sales Exception for Option-Type Contracts and Forward
Contracts in Electricity." Therefore, contracts that the Company holds for the
sale of power in future periods that meet the criteria in DIG Issue No. C15 have
been designated as "normal purchases, normal sales" contracts, and are exempted
from recognition in the Consolidated Financial Statements until power is
delivered.
North American Merchant Generation
The Company's wholesale energy portfolio in North America includes the merchant
generation facilities and trading contracts held for power, natural gas, crude
oil and petroleum products. The merchant generation facilities portion of the
wholesale energy portfolio is anticipated to be realized in future periods as
the generation facilities are dispatched. This future value includes hedge
contracts and contracts designated as normal purchases and normal sales. Only
the contracts designated and effective as qualifying hedges are reflected on the
Company's Consolidated Balance Sheets at fair value. Changes in the fair value
of qualifying hedging contracts do not affect current-period earnings. Normal
purchases and normal sales contracts are not subject to accounting recognition
until contract performance occurs.
The remaining portion of the total estimated value of the wholesale energy
portfolio is attributed to the current value of trading contracts. These
contracts are subject to MTM accounting and changes in the contract fair value
are recorded as part of current-period earnings.
The following table shows when the expected discounted value of the Company's
North American merchant generation facilities portion of the portfolio will be
realized in future periods. The table reflects the estimated value of the
Company's ability to manage its power plants as options to convert natural gas
into power. The estimate is derived from the current forward market prices of
fuels and power, less variable plant operating expenses through June 30, 2011
only and not for the life of the asset portfolio. It includes the value
associated with hedge transactions and contracts designated as normal purchases
and normal sales, but it does not include the value of any mark-to-market
trading positions or hedges. Fixed operating costs, overhead, depreciation,
taxes, reserves and future capital expenditures are excluded, and the value
presented is not intended to reflect fair market value of the portfolio.
30
======================================================================================================
North American Merchant Generation Portfolio Value as of June 30, 2002 (in millions)
------------------------------------------------------------------------------------------------------
Maturity in 2005 Total
Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter/a/ Portfolio Value
------------------------------------------------------------------------------------------------------
$553 $695 $764 $4,389 $6,401
======================================================================================================
/a/ For purposes of calculating total portfolio value, model valuations were
calculated through June 2011.
Commodity Price Risk
The Company, substantially through its subsidiaries, is exposed to the impact of
market fluctuations in the price of natural gas, electricity and other
energy-related products marketed and purchased. The Company employs established
policies and procedures to manage its risks associated with these market
fluctuations using various commodity derivatives, including forward contracts,
futures, swaps and options for trading purposes and for activity other than
trading activity (primarily hedge strategies). (See Notes 2 and 4 to the
Consolidated Financial Statements.)
Trading. The risk in the trading portfolio is measured and monitored on a daily
basis utilizing a Value-at-Risk model to determine the potential one-day
favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is
monitored daily in comparison to established thresholds. Other measures are also
used to limit and monitor risk in the trading portfolio (which includes all
trading contracts not designated as hedge positions) on monthly and annual
bases. These measures include limits on the nominal size of positions and
periodic loss limits.
DER computations are based on historical simulation, which uses price movements
over a specified period (generally ranging from seven to 14 days). The
historical simulation emphasizes the most recent market activity, which is
considered the most relevant predictor of immediate future market movements for
natural gas, electricity and other energy-related products. DER computations use
several key assumptions, including a 95% confidence level for the resultant
price movement and the holding period specified for the calculation. The
Company's DER amounts for instruments held for trading purposes are shown in the
following table.
=====================================================================================================================
Daily Earnings at Risk (in millions)
- ---------------------------------------------------------------------------------------------------------------------
Estimated Average Estimated Average
One-Day Impact on One-Day Impact on High One-Day Impact Low One-Day Impact
EBIT for 2nd Quarter EBIT for 2nd Quarter on EBIT for 2nd on EBIT for 2nd
2002/a/ 2001/a/ Quarter 2002/a/ Quarter 2002/a/
- ---------------------------------------------------------------------------------------------------------------------
Calculated DER $12 $14 $19 $8
=====================================================================================================================
/a/Amount does not include the impact of Westcoast's trading activity.
DER is an estimate based on historical price volatility. Actual volatility can
exceed assumed results. DER also assumes a normal distribution of price changes;
thus, if the actual distribution is not normal, the DER may understate or
overstate actual results. DER is used to estimate the risk of the entire
portfolio, and for locations that do not have daily trading activity, it may not
accurately estimate risk due to limited price information. Stress tests are
employed in addition to DER to measure risk where market data information is
limited. In the current DER methodology, options are modeled in a manner
equivalent to forward contracts which may understate the risk.
31
The Company's exposure to commodity price risk is influenced by a number of
factors, including contract size, length, market liquidity, location and unique
or specific contract terms. The following table illustrates the movements in the
fair value of the Company's trading instruments during the three months ended
June 30, 2002.
=======================================================================================================
Changes in Fair Value of Trading Contracts (in millions)
- -------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at the beginning of the year $ 839
Contracts realized or otherwise settled during the period 194
Fair value of contracts entered into during the period 39
Changes in fair value amounts attributable to changes in valuation techniques/a/ (14)
Other changes in fair values (77)
----------------------
Fair value of contracts outstanding at the end of the period $ 981
=======================================================================================================
/a/Amount represents appreciation of the fair value of the mark-to-market
portfolio as a result of applying improved and standardized valuation modeling
techniques.
For the three months ended June 30, 2002, the unrealized net gain recognized in
operating income was $57 million compared to a $61 million loss for the first
quarter of 2002. The fair value of these contracts is expected to be realized in
future periods, as detailed in the following table. The amount of cash
ultimately realized for these contracts will differ from the amounts shown in
the following table due to factors such as market volatility, counterparty
default and other unforeseen events that could impact the amount and/or
realization of these values.
When available, the Company uses observable market prices for valuing its
trading instruments. When quoted market prices are not available, management
uses established guidelines for the valuation of these contracts. Management may
use a variety of reasonable methods to assist in determining the valuation of a
trading instrument, including analogy to reliable quotations of similar trading
instruments, pricing models, matrix pricing and other formula-based pricing
methods. These methodologies incorporate factors for which published market data
may be available. All valuation methods employed by the Company are approved by
an independent internal corporate risk management organization.
The following table shows the fair value of the Company's trading portfolio as
of June 30, 2002.
- -------------------------------------------------------------------------------------------------------------
Fair Value of Trading Contracts as of June 30, 2002 (in millions)
- -------------------------------------------------------------------------------------------------------------
Maturity in
Maturity in Maturity in Maturity in 2005 and Total Fair
Sources of Fair Value 2002 2003 2004 Thereafter Value
- -------------------------------------------------------------------------------------------------------------
Prices supported by quoted market
prices and other external sources $ 215 $ 181 $ 108 $ 38 $ 542
Prices based on models and
other valuation methods 36 29 52 322 439
- -------------------------------------------------------------------------------------------------------------
Total $ 251 $ 210 $ 160 $ 360 $ 981
- -------------------------------------------------------------------------------------------------------------
The "prices supported by quoted market prices and other external sources"
category includes the Company's New York Mercantile Exchange (NYMEX) futures
positions in natural gas and crude oil. The NYMEX has currently quoted prices
for the next 32 months. In addition, this category includes the Company's
forward positions and options in natural gas and power and natural gas basis
swaps at points for which over-the-counter (OTC) broker quotes are available. On
average, OTC quotes for natural gas and power forwards and swaps extend 22 and
32 months into the future, respectively. OTC quotes for natural gas and power
options extend 12 months into the future, on average. The Company values these
positions against internally developed forward market price curves that are
constantly validated and recalibrated against OTC broker quotes. This category
also includes "strip" transactions whose prices are obtained from external
sources and then modeled to daily or monthly prices as appropriate.
32
The "prices based on models and other valuation methods" category includes (i)
the value of options not quoted by an exchange or OTC broker, (ii) the value of
transactions for which an internally developed price curve was constructed as a
result of the long dated nature of the transaction or the illiquidity of the
market point, and (iii) the value of structured transactions. It is important to
understand that in certain instances structured transactions can be decomposed
and modeled by the Company as simple forwards and options based on prices
actively quoted. Although the valuation of the simple structures might not be
different from the valuation of contracts in other categories, the effective
model price for any given period is a combination of prices from two or more
different instruments and therefore have been included in this category due to
the complex nature of these transactions.
The Company's trading portfolio valuation adjustments for liquidity, credit and
cost of service are reflected in the above amounts.
Hedging Strategies. The Company's subsidiaries are exposed to market
fluctuations in the prices of energy commodities related to their power
generating and natural gas gathering, processing and marketing activities. The
Company closely monitors the risks associated with these commodity price changes
on its future operations and, where appropriate, uses various commodity
instruments such as electricity, natural gas, crude oil and NGL contracts to
hedge the value of its assets and operations from such price risks. In
accordance with SFAS No. 133, the Company's primary use of energy commodity
derivatives is to hedge the output and production of assets it physically owns.
Contract terms are up to 30 years. These contracts are designated and qualify as
effective hedge positions of future cash flows, or fair values of assets owned
by the Company, to the extent that the hedge relationships are effective, their
market value change impacts are not recognized in current earnings. The
unrealized gains or losses on these contracts are deferred in Other
Comprehensive Income (OCI) for cash flow hedges and included in Other Current or
Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair
value hedges of firm commitments, in accordance with SFAS No. 133. Amounts
deferred in OCI are realized in earnings concurrently with the transaction being
hedged. (See Notes 2 and 4 to the Consolidated Financial Statements.) However,
in instances where the hedging contract no longer qualifies for hedge
accounting, amounts included in OCI through the date of de-designation remain in
OCI until the underlying transaction actually occurs. The derivative contract
(if continued as an open position) will be marked to market currently through
earnings. Several factors influence the effectiveness of a hedge contract,
including counterparty credit risk and using contracts with different
commodities or unmatched terms. Hedge effectiveness is monitored regularly and
measured each month.
Power Price Exposure. As of June 30, 2002, DENA's expected economic output of
the merchant generation facilities was 72%, 56% and 55% hedged for 2003, 2004
and 2005, respectively, with respect to its exposure to power prices. These
percentages hedged do not refer to the maximum capacity of the facilities.
DENA's expected economic output is determined based on current forward spark
spreads, current market volatilities for gas and power, the correlation between
gas and power and variable operating expenses. The expected economic output will
change as market conditions change.
The following table shows when gains and losses deferred on the Consolidated
Balance Sheets for derivative instruments qualifying as effective hedges of firm
commitments or anticipated future transactions will be recognized into earnings.
Contracts with terms extending several years are generally valued using models
and assumptions developed internally or by industry standards. However, as
mentioned previously, the gains and losses for these contracts are not
recognized in earnings until settlement at their then market price. Therefore,
assumptions and valuation techniques for these contracts have no impact on
reported earnings prior to settlement.
The fair value of the Company's qualifying hedge positions at a point in time is
not necessarily indicative of the value realized when such contracts settle.
33
======================================================================================================
Fair Value of Hedge Position Contracts as of June 30, 2002 (in millions)/a/
------------------------------------------------------------------------------------------------------
Maturity in 2005 Total
Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter Contract Value
--------------------- ------------------- ------------------- ------------------- --------------------
$ 218 $ 157 $ 141 $ 231 $ 747
======================================================================================================
/a/ Includes foreign currency and interest rate hedges that net to approximately
a $7 million loss
In addition to the hedge contracts described above and recorded on the
Consolidated Balance Sheets, the Company enters into other contracts that
qualify for the normal purchases and sales exemption described in Paragraph 10
of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward
agreements to sell power, bear the same counterparty credit risk as the hedge
contracts described above. Under the same risk reduction guidelines used for
other contracts, normal purchases and sales contracts are also subject to
collateral requirements. Income recognition and realization related to these
contracts coincide with the physical delivery of power.
Credit Risk
The Company's principal customers for power and natural gas marketing services
are industrial end-users, marketers and utilities located throughout the U.S.,
Canada, Asia Pacific, Europe and Latin America. The Company has concentrations
of receivables from natural gas and electric utilities and their affiliates, as
well as industrial customers throughout these regions. These concentrations of
customers may affect the Company's overall credit risk in that some customers
may be similarly affected by changes in economic, regulatory or other factors.
Where exposed to credit risk, the Company analyzes the counterparties' financial
condition prior to entering into an agreement, establishes credit limits and
monitors the appropriateness of those limits on an ongoing basis. The Company
frequently uses master collateral agreements to mitigate credit exposure. The
collateral agreement provides for a counterparty to post cash or letters of
credit for exposure in excess of the established threshold. The threshold amount
represents an open credit limit, determined in accordance with the corporate
credit policy. The collateral agreement also provides that the inability to post
collateral is sufficient cause to terminate a contract and liquidate all
positions.
Despite the current challenges in the energy sector, management believes that
the credit risk management process described above is operating effectively. As
of June 30, 2002, the Company held cash or letters of credit of $927 million to
secure such future performance, and had deposited with counterparties $157
million of such collateral to secure its obligations to provide such future
services. Collateral amounts held or posted vary depending on the value of the
underlying contracts and cover trading, normal purchases and normal sales, and
hedging contracts outstanding. The Company may be required to return held
collateral and post additional collateral should price movements adversely
impact the value of open contracts or positions. The Company's and its
counterparties' publicly disclosed credit ratings impact the amounts of
additional collateral to be posted.
The change in market value of NYMEX-traded futures and options contracts
requires daily cash settlement in margin accounts with brokers. Financial
derivatives are generally cash settled periodically throughout the contract
term. However, these transactions are also generally subject to margin
agreements with many of the Company's counterparties.
As of June 30, 2002, the Company had a pre-tax bad debt provision of $90 million
related to receivables for energy sales in California. Following the bankruptcy
of Enron Corporation, the Company terminated substantially all contracts with
Enron Corporation and its affiliated companies (collectively, Enron). As a
result, in 2001 the Company recorded, as a charge, a non-collateralized
accounting exposure of $19 million. The $19 million non-collateralized
accounting exposure was composed of charges of $12 million at DENA, $3 million
at International Energy, $3 million at Field Services and $1 million at Natural
Gas Transmission. These amounts were stated on a pre-tax basis as charges
against the reporting segment's earnings in 2001.
34
The Company's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$19 million. Any bankruptcy claims that exceed this amount would primarily
relate to termination and settlement rights under contracts and transactions
with Enron that would have been recognized in future periods, and not in the
historical periods covered by the financial statements to which the $19 million
charge relates.
Substantially all contracts with Enron were completed or terminated prior to
December 31, 2001. The Company has continuing contractual relationships with
certain Enron affiliates, which are not in bankruptcy. In Brazil, a power
purchase agreement between a Company affiliate, Companhia de Geracao de Energia
Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A
(Elektro), a distribution company approximately 100% owned by Enron, will expire
December 31, 2005. The contract was executed by the Company's predecessor in
interest in Paranapanema, and obligates Paranapanema to provide energy to
Elektro on an irrevocable basis for the contract period. In addition, a
purchase/sale agreement expiring September 1, 2005 between a Company affiliate
and Citrus Trading Corporation (Citrus), a 50/50 joint venture between Enron and
El Paso Corporation, continues to be in effect. The contract requires the
Company affiliate to provide liquefied natural gas to Citrus. Citrus has
provided a letter of credit in favor of the Company to cover its exposure.
Interest Rate Risk
The Company is exposed to risk resulting from changes in interest rates as a
result of its issuance of variable-rate debt, fixed-to-floating interest rate
swaps, commercial paper and auction rate market preferred stock. The Company
manages its interest rate exposure by limiting its variable-rate and fixed-rate
exposures to percentages of total capitalization, as set by policy, and by
monitoring the effects of market changes in interest rates. The Company also
enters into financial derivative instruments, including, but not limited to,
interest rate swaps, options, swaptions and lock agreements to manage and
mitigate interest rate risk exposure. (See Notes 2, 4, and 6 to the Consolidated
Financial Statements.)
Equity Price Risk
The Company and its subsidiaries participate in Duke Energy's employee benefit
plans. Duke Energy's costs of providing non-contributory defined benefit
retirement and postretirement benefit plans are dependent upon a number of
factors, such as the rates of return on plan assets, discount rate, the rate of
increase in health care costs and contributions made to the plans. The market
value of Duke Energy's plan assets has been affected by declines in the equity
market since the third quarter of 2000. As a result, at December 31, 2002, Duke
Energy could be required to recognize an additional minimum liability as
prescribed by SFAS No. 87 "Employers' Accounting for Pensions" and SFAS No. 132
"Employers' Disclosures about Pensions and Postretirement Benefits." The
liability would be recorded as a reduction to OCI, and would not affect net
income for 2002. The amount of the liability, if any, will depend upon the asset
returns experienced in 2002 and contributions made by Duke Energy to the plans
during 2002. Duke Energy is currently evaluating whether to make cash
contributions to the plans. The liability recorded or cash contributions to the
plans could be material in 2002. Also, pension cost and cash funding
requirements could increase in future years without a substantial recovery in
the equity markets. When the fair value of the plan assets exceeds the
accumulated benefit obligations, the recorded liability will be reduced and OCI
will be restored in the Consolidated Balance Sheet.
Foreign Currency Risk
The Company is exposed to foreign currency risk from investments in
international affiliates and businesses owned and operated in foreign countries.
To mitigate risks associated with foreign currency fluctuations, when possible,
transactions may be denominated in or indexed to the U.S. dollar and/or local
inflation rates, or investments may be hedged through debt denominated or issued
in the foreign currency. The Company also uses foreign currency derivatives,
where possible, to manage its risk related to foreign currency fluctuations. To
monitor its currency exchange rate risks, the Company uses sensitivity analysis,
which measures the impact of devaluation of the foreign currencies to which it
has exposure.
35
Since 1991, the Argentine peso has been pegged to the U.S. dollar at a fixed 1:1
exchange ratio. In December 2001, the Argentine government imposed a restriction
that limited cash withdrawals above a certain amount and foreign money
transfers. Financial institutions were allowed to conduct limited activity as a
bank and exchange holiday was announced, and currency exchange activity was
essentially halted. In January 2002, the Argentine government announced the
creation of a dual-currency system. Subsequently, however, the Argentine
government has decided to use a free-floating currency.
The Company's investment in Argentina was U.S. dollar functional as of December
31, 2001. Once a functional currency determination has been made, that
determination must be adhered to consistently, unless significant changes in
economic factors indicate that the entity's functional currency has changed. The
recent events in Argentina require a change. In January 2002, the functional
currency of the Company's investment in Argentina changed from the U.S. dollar
to the Argentine peso. In compliance with SFAS No. 52, "Foreign Currency
Translation," the change in functional currency will be made prospectively.
Management believes that the events in Argentina will have no material adverse
effect on the Company's future consolidated results of operations, cash flows or
financial position.
CURRENT ISSUES
Notice of Proposed Rulemaking (NOPR) on Standards of Conduct. In September 2001,
the Federal Energy Regulatory Commission (FERC) issued a NOPR announcing that it
is considering new regulations regarding standards of conduct that would apply
uniformly to natural gas pipelines that are currently subject to different gas
standards. The proposed standards would change how companies and their
affiliates interact and share information by broadening the definition of
"affiliate" covered by the standards of conduct. Various entities filed comments
on the NOPR with the FERC, including the Company's parent company, Duke Energy,
which filed in December 2001. In April 2002 the FERC Staff issued an analysis of
the comments received by the FERC. In several areas, the staff's analysis
reflects important changes to the NOPR. However, with regard to corporate
governance, the staff's analysis recommended adoption of an automatic imputation
rule which could impact parent company oversight of subsidiaries with
transmission functions (pipeline and storage functions). Duke Energy filed
supplemental comments in June 2002. A final rule is expected in the fall of
2002.
At its meeting in July 2002, the FERC issued its 600-page Standard Market Design
NOPR. The NOPR has major implications for the delivery of electric energy
throughout the U.S. Major elements of the FERC proposal include: (a) The use of
Network Access Service to replace the existing network and point-to-point
services. All customers, including load serving entities on behalf of bundled
retail load, would be required to take this service under a new pro forma
tariff. There would be no transmission rate pancaking among regions because
through-and-out charges would be eliminated. (b) By July 31, 2003, vertically
integrated utilities would be required to retain Independent Transmission
Providers to administer the new tariff and functionally operate transmission
systems. (c) Congestion management would be provided through the use of
Locational Marginal Pricing, a transparent method of pricing transmission
congestion costs as a component of energy transactions in a given market. Market
participants would be allocated or could purchase Congestion Revenue Rights to
manage congestion risk. (d) The formation of Regional State Advisory Committees
and other regional entities to coordinate the planning, certification and siting
of new transmission facilities in cooperation with states. Some of these
features are likely to be highly contested by the various stakeholders.
36
The Company has initiated a detailed review of the NOPR. Initial comments on the
NOPR are due to the FERC by October 15, 2002. The FERC has indicated that it
intends to issue a final rule by February 2003. While the NOPR is complex, and
remains under review, the early indications are that it appears unlikely to
materially impact the consolidated financial statements of the Company.
Litigation and Contingencies. California Matters. Duke Energy, some of the
Company's subsidiaries, and three current or former executives have been named
as defendants, among numerous other corporate and individual defendants, in one
or more of a total of 14 lawsuits, filed in California on behalf of purchasers
of electricity in the State of California, with one suit filed on behalf of a
Washington State electricity purchaser. Most of these lawsuits seek class action
certification and damages, and other relief, as a result of the defendants'
alleged unlawful manipulation of the California wholesale electricity markets.
These lawsuits generally allege that the defendants manipulated the wholesale
electricity markets in violation of state laws against unfair and unlawful
business practices and, in some suits, in violation of state antitrust laws.
Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The
lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained
revenues for sales of electricity and, in some lawsuits, an award of treble
damages for alleged violations of state antitrust laws.
The first six of these lawsuits were filed in late 2000 through mid-2001 and
have been consolidated before a single judge in San Diego. The plaintiffs in the
six lawsuits filed a joint Master Amended Complaint in March 2002, which adds
additional defendants. The claims against the defendants are similar to those in
the original complaints. In April 2002, some defendants, including Duke Energy,
filed cross-complaints against various market participants not named as
defendants in the plaintiffs' original and amended complaints.
Eight of these 14 suits were filed in mid-2002, seven by plaintiffs in
California and one by a plaintiff in the State of Washington. These eight suits
are being considered for consolidation with the six previously filed lawsuits.
These matters are in their earliest stages. The Company is currently evaluating
these claims and intends to vigorously defend itself.
The Company and its subsidiaries are involved in other legal and regulatory
proceedings and investigations related to activities in California. These other
activities were disclosed in the Company's Form 10-K for the year ended December
31, 2001, and there have been no new material developments in relation to these
issues.
Trading Matters. Since April 2002, 16 shareholder class action lawsuits have
been filed against Duke Energy: 13 in the United States District Court for the
Southern District of New York and three in the United States District Court for
the Western District of North Carolina. Some of the lawsuits also name as
co-defendants some Duke Energy executives, Duke Energy's independent external
auditor and various investment banking firms. In addition, Duke Energy has
received a shareholder's derivative notice demanding that it commence litigation
against named executives and directors of Duke Energy for alleged breaches of
fiduciary duties and insider trading. Duke Energy has also received a second
similar shareholder's derivative notice demanding litigation against named
executives and directors for alleged failure to prevent damages caused to Duke
Energy arising from "round-trip" trading. Duke Energy's response date to the
first derivative demand has been extended to after the first of the year 2003.
Duke Energy is negotiating a similar agreement with respect to the second
derivative demand.
The class actions and the threatened shareholder derivative claims arise out of
allegations that Duke Energy improperly engaged in the so-called "round trip"
trades which resulted in an alleged overstatement of revenues over a three-year
period of approximately $1 billion. The plaintiffs seek recovery of an unstated
amount of compensatory damages, attorneys' fees and costs for alleged violations
of securities laws. In one of the lawsuits, the plaintiffs assert a common law
fraud claim and seek, in addition to compensatory damages, disgorgement and
punitive damages. These matters are in their earliest stages. Duke Energy is
currently evaluating these claims and intends to vigorously defend itself.
37
In 2002, Duke Energy received and responded to information requests from the
FERC, an informal request for information from the SEC, and a subpoena from the
Commodity Futures Trading Commission. Duke Energy also received and will respond
to a grand jury subpoena issued by the U.S. Attorney's office in Houston. All
information requests and subpoenas seek documents and information related to
trading activities, including so-called "round-trip" trading. Duke Energy is
cooperating with the respective governmental agencies on each of these
inquiries.
Duke Energy submitted a final report to the SEC based on a review of
approximately 750,000 trades made by various Duke Energy subsidiaries between
January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review
of trading, accounting, and other records, with the assistance of Duke Energy
senior legal, corporate risk management and accounting personnel. Duke Energy
identified 28 "round-trip" transactions done for the apparent purpose of
increasing volumes on the Intercontinental Exchange and 61 "round-trip"
transactions done at the direction of one of Duke Energy's traders that did not
have a legitimate business purpose and were contrary to corporate policy. Duke
Energy determined that the financial impact of these "round trip" transactions
was not material.
As a result of the trading review, Duke Energy has terminated two employees and
put in place additional risk management procedures to improve and strengthen the
oversight and controls of its trading operations. Duke Energy has also
reconfirmed to employees that engaging in simultaneous or prearranged
transactions that lack a legitimate business purpose, or any trading activities
that lack a legitimate business purpose, is against company policy. Beginning
August 1, 2002, North American trading and marketing functions currently in
DENA, including DETM and the Canadian trading operations, will be consolidated
into one group. This organization will develop consistent policies, practices
and systems for the entire trading and marketing operation and implement better
control systems to improve monitoring and reporting capabilities.
Price Mitigation Matters. In November 2001, Nevada Power Company and Sierra
Pacific Power Company (collectively, the Power Companies) filed a complaint with
the FERC against DETM. The complaint requests the FERC to mitigate prices in
sales contracts between the Company and Nevada Power, and the Company and Sierra
Pacific that were entered into between December 7, 2000 and June 20, 2001. The
Power Companies allege that the contract prices are unjust and unreasonable
because they were entered into during a period that the FERC determined the
California market to be dysfunctional and uncompetitive, and that the California
market influenced the contract prices. In April 2002, the FERC issued an order
which provides for an evidentiary hearing, establishes refund dates, and
requires the parties to participate in settlement negotiations. The parties have
reached a settlement pursuant to which the Power Companies dismissed their
complaint against DETM in June 2002. As part of this settlement, the Company has
agreed to supply up to 1,000 megawatts of electricity per hour, as well as
natural gas, to the Power Companies to fulfill customers' power requirements
during the peak summer period. In addition, the Company will further provide
real-time purchases and sales of power between June 15th and December 31, 2002,
under mutually agreeable terms to assist the Power Companies in balancing
electricity demands. DETM is an intervener in cases against other sellers to
these two utilities, but is no longer a respondent in this proceeding.
In July 2002, the Sacramento Municipal Utility District (SMUD) filed a complaint
with the FERC against DETM requesting that the FERC mitigate unjust and
unreasonable prices in four mid- and long-term sales contracts between DETM and
SMUD entered into between February 7, 2001 and March 26, 2001. SMUD, alleging
that DETM had the ability to exercise market power, claims that the contract
prices are unjust and unreasonable because they were entered into during a
period that the FERC determined the western markets to be dysfunctional and
uncompetitive and that the western markets influenced their price. In support of
its request to mitigate the contract price, SMUD relies on the fact that the
contract prices are higher than prices in the western U.S. following
implementation of the FERC's June 2001 price mitigation plan. SMUD requests the
FERC to set "just and reasonable" contract rates and to promptly set a refund
effective date.
38
The Company and its subsidiaries are involved in other legal, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding performance, contracts and other matters arising in the
ordinary course of business, some of which involve substantial amounts.
Management believes that the final disposition of these proceedings will have no
material adverse effect on consolidated results of operations, cash flows or
financial position.
New Accounting Standards. In June 2001, the FASB issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. The
standard applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and (or) normal use of the asset.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability is increased due to
the passage of time based on the time value of money until the obligation is
settled.
The Company is required and plans to adopt the provisions of SFAS No. 143 as of
January 1, 2003. To accomplish this, the Company must identify any legal
obligations for asset retirement obligations, and determine the fair value of
these obligations on the date of adoption. The determination of fair value is
complex and requires gathering market information and developing cash flow
models. Additionally, the Company will be required to develop processes to track
and monitor these obligations. Because of the effort needed to comply with the
adoption of SFAS No. 143, the Company is currently assessing the new standard
but has not yet determined the impact on its consolidated results of operations,
cashflows or financial position.
In June 2002, the EITF reached a partial consensus on Issue No. 02-03,
"Recognition and Reporting of Gains and Losses on Energy Trading Contracts under
EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities," and EITF No. 00-17, "Measuring the Fair Value of
Energy-Related Contracts in Applying Issue No. 98-10." The EITF concluded that,
effective for periods ending after July 15, 2002, mark-to-market gains and
losses on energy trading contracts (including those to be physically settled)
must be shown on a net basis in the Consolidated Statements of Income.
Comparative financial statements for prior periods must be reclassified to
reflect presentation on a net basis. Also, companies must disclose volumes of
physically settled energy trading contracts. The Company is evaluating the
impact of this new consensus on the presentation of its Consolidated Statements
of Income, but believes it will have a material impact on total revenues and
expenses. The partial consensus will have no impact on current or prior net
income.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." The Company will adopt the provisions of
SFAS No. 146 for restructuring activities initiated after December 31, 2002.
SFAS No. 146 requires that the liability for costs associated with an exit or
disposal activity be recognized when the liability is incurred. Under EITF No.
94-3, a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized.
Subsequent Events. Westcoast has entered into an agreement to sell its 60%
interest in the Frederickson Power Project for cash proceeds of approximately
$100 million. The Company expects to record a pre-tax gain of approximately $2
million upon completion of the transaction, which is subject to regulatory
approvals and is expected to be finalized by the end of the third quarter of
2002.
39
In July 2002, Duke Energy International, LLC, a wholly owned subsidiary of Duke
Energy, acquired a 103 megawatt gas-fired combined heat and power plant located
in northwest France for approximately $69 million.
40
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
In June 2001, the Company's subsidiary, Duke Energy Field Services, LLC (DEFS)
received two administrative Compliance Orders from the New Mexico Environment
Department (NMED) seeking civil penalties for primarily historic air permit
matters. One order alleged specific permit non-compliance at 11 facilities that
occurred periodically between 1996 and 1999. Allegations under this order
related primarily to emissions from some compressor engines in excess of what
were then new operating permit limits. The other order alleged numerous
unexcused excursions from an hourly permit limit arising from upset events at
one facility's sulfur recovery unit between 1997 and 2001. NMED applied its
civil penalty policy to the alleged violations and calculated the penalties to
be $10 million in the aggregate. In May 2002, DEFS and NMED entered into a
Settlement Agreement which resolves all aspects of the June 2001 Compliance
Orders. Under the terms of the Settlement Agreement, no penalty will be
assessed, and DEFS has agreed to undertake upgrades at several of its facilities
in New Mexico that will significantly reduce emissions and will also ensure
those facilities are achieving state ambient air quality standards.
DEFS was in discussion with the Oklahoma Department of Environmental Quality
(ODEQ) regarding apparent non-compliance issues relating to DEFS' Title V Clean
Air Act Operating permits at its Oklahoma facilities, primarily consisting of
compliance issues disclosed to the ODEQ pursuant to permit requirements or
otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance issues
relate to various specific and detailed terms of the Title V permits, including,
separate filing requirements, engine testing procedural requirements,
certification requirements, and quarterly emissions testing obligations. In May
2002, DEFS and ODEQ entered into a Consent Order to address and resolve all of
the items of non-compliance with Title V permits as discussed above. Under the
Consent Order, DEFS agreed to pay a civil penalty of $85,050 and install
pollution control equipment on some of its compressor engines to achieve
significant emissions reductions at a cost of approximately $482,000. The items
of non-compliance have been corrected, and the installation of the pollution
controls is presently underway.
For additional information concerning litigation and other contingencies, see
Note 7 to the Consolidated Financial Statements, "Commitments and
Contingencies," and Item 3, "Legal Proceedings," and Note 12 to the Consolidated
Financial Statements, "Commitments and Contingencies," included in the Company's
Form 10-K for December 31, 2001, which are incorporated herein by reference.
Management believes that the resolution of these proceedings will have no
material adverse effect on the Company's consolidated results of operations,
cash flows or financial position.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
Exhibit
Number
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed on April 15, 2002 contained
disclosures under Item 5, Other Events, and Item 7, Exhibits.
41
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
August 14, 2002 /s/ Robert P. Brace
----------------------------
Robert P. Brace
Vice President and
Chief Financial Officer
August 14, 2002 /s/ Keith G. Butler
----------------------------
Keith G. Butler
Controller
42