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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_______________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended March 31, 2003 Commission File Number 1-4928
DUKE ENERGY CORPORATION
(Exact name of Registrant as Specified in its Charter)
North Carolina 56-0205520
(State or Other (IRS Employer
Jurisdiction of Incorporation) Identification No.)
526 South Church Street
Charlotte, NC 28202-1803
(Address of Principal Executive Offices)
(Zip code)
704-594-6200
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes X No ___
---
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes (x) No ( )
Indicate the number of shares outstanding of each of the Issuer's classes of
common stock, as of the latest practicable date.
Number of shares of Common Stock, without par value, outstanding at April 30,
2003......901,148,372
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DUKE ENERGY CORPORATION
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2003
INDEX
Item Page
- ---- ----
PART I. FINANCIAL INFORMATION
1. Financial Statements ................................................................... 1
Consolidated Statements of Income for the Three Months Ended March 31,
2003 and 2002 .................................................................... 1
Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002 ............. 2
Consolidated Statements of Cash Flows for the Three Months Ended March 31,
2003 and 2002 .................................................................... 4
Consolidated Statements of Comprehensive Income (Loss) for the Three Months
Ended March 31, 2003 and 2002 .................................................... 5
Notes to Consolidated Financial Statements ......................................... 6
2. Management's Discussion and Analysis of Results of Operations and Financial Condition .. 27
3. Quantitative and Qualitative Disclosures about Market Risk ............................. 39
4. Controls and Procedures ................................................................ 39
PART II. OTHER INFORMATION
1. Legal Proceedings ...................................................................... 40
4. Submission of Matters to a Vote of Security Holders .................................... 40
6. Exhibits and Reports on Form 8-K ....................................................... 40
Signatures ............................................................................. 41
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Duke Energy 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 Duke Energy's intentions,
plans, expectations, assumptions and beliefs about future events and are subject
to risks, uncertainties and other factors. Many of those factors are outside
Duke Energy's control and could cause actual results to differ materially from
the results expressed or implied by those forward-looking statements. Those
factors include:
. State, federal and foreign legislative and regulatory initiatives that
affect cost and investment recovery, have an impact on rate
structures, and affect the speed at and degree to which competition
enters the electric and natural gas industries
. The outcomes of litigation and regulatory investigations, proceedings
or inquiries
. Industrial, commercial and residential growth in Duke Energy's service
territories
. The weather and other natural phenomena
. The timing and extent of changes in commodity prices, interest rates
and foreign currency exchange rates
. General economic conditions, including any potential effects arising
from terrorist attacks, the situation in Iraq and any consequential
hostilities or other hostilities
. Changes in environmental and other laws and regulations to which Duke
Energy and its subsidiaries are subject or other external factors over
which Duke Energy has no control
i
. The results of financing efforts, including Duke Energy's ability to
obtain financing on favorable terms, which can be affected by various
factors, including Duke Energy's credit ratings and general economic
conditions
. Lack of improvement or further declines in the market prices of equity
securities and resultant cash funding requirements for Duke Energy's
defined benefit pension plans
. The level of creditworthiness of counterparties to Duke Energy's
transactions
. The amount of collateral required to be posted from time to time in
Duke Energy's transactions
. Growth in opportunities for Duke Energy's business units, including
the timing and success of efforts to develop domestic and
international power, pipeline, gathering, processing and other
infrastructure projects
. The performance of electric generation,pipeline and gas processing
facilities
. The extent of success in connecting natural gas supplies to gathering
and processing systems and in connecting and expanding gas and
electric markets and
. The effect of accounting pronouncements issued periodically by
accounting standard-setting bodies
In light of these risks, uncertainties and assumptions, the events described in
the forward-looking statements might not occur or might occur to a different
extent or at a different time than Duke Energy has described. Duke Energy
undertakes no obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In millions, except per share amounts)
Three Months Ended
March 31,
-------------------
2003 2002
-------------------
Operating Revenues
Sales of natural gas and petroleum products $ 4,085 $ 981
Generation, transmission and distribution of electricity 1,742 1,587
Transportation and storage of natural gas 436 326
Trading and marketing net (loss) margin (90) 244
Other 151 170
------- -------
Total operating revenues 6,324 3,308
------- -------
Operating Expenses
Natural gas and petroleum products purchased 3,689 894
Fuel used in electric generation 299 315
Net interchange and purchased power 125 108
Operation and maintenance 728 852
Depreciation and amortization 449 344
Property and other taxes 141 127
------- -------
Total operating expenses 5,431 2,640
------- -------
Operating Income 893 668
------- -------
Other Income and Expenses
Equity in earnings of unconsolidated affiliates 34 9
Gain on sale of equity investments 14 14
Other income and expenses, net 33 79
------- -------
Total other income and expenses 81 102
Interest Expense 340 198
Minority Interest Expense 52 32
------- -------
Earnings Before Income Taxes 582 540
Income Taxes 195 158
------- -------
Income Before Cumulative Effect of Change in Accounting Principles 387 382
Cumulative Effect of Change in Accounting Principles, net of tax and
minority interest (162) -
------- -------
Net Income 225 382
Preferred and Preference Stock Dividends 3 3
------- -------
Earnings Available For Common Stockholders $ 222 $ 379
======= =======
Common Stock Data
Weighted-average shares outstanding 897 788
Earnings per share (before cumulative effect of change in accounting
principles)
Basic $ 0.43 $ 0.48
Diluted $ 0.43 $ 0.48
Earnings per share
Basic $ 0.25 $ 0.48
Diluted $ 0.25 $ 0.48
Dividends per share $ 0.275 $ 0.275
See Notes to Consolidated Financial Statements.
1
CONSOLIDATED BALANCE SHEETS
(In millions)
March 31,
2003 December 31,
(Unaudited) 2002
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 1,109 $ 857
Receivables 7,422 6,766
Inventory 946 1,134
Unrealized gains on mark-to-market and hedging transactions 2,337 2,144
Other 1,074 952
------- -------
Total current assets 12,888 11,853
------- -------
Investments and Other Assets
Investments in unconsolidated affiliates 2,110 2,066
Nuclear decommissioning trust funds 713 708
Goodwill, net of accumulated amortization 3,730 3,747
Notes receivable 463 589
Unrealized gains on mark-to-market and hedging transactions 2,325 2,480
Other 1,751 1,645
------- -------
Total investments and other assets 11,092 11,235
------- -------
Property, Plant and Equipment
Cost 49,815 48,677
Less accumulated depreciation and amortization 12,885 12,458
------- -------
Net property, plant and equipment 36,930 36,219
------- -------
Regulatory Assets and Deferred Debits
Deferred debt expense 260 263
Regulatory asset related to income taxes 973 936
Other 1,102 460
------- -------
Total regulatory assets and deferred debits 2,335 1,659
------- -------
Total Assets $63,245 $60,966
======= =======
See Notes to Consolidated Financial Statements.
2
CONSOLIDATED BALANCE SHEETS
(In millions)
March 31,
2003 December 31,
(Unaudited) 2002
----------------- -------------
LIABILITIES AND COMMON STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 6,559 $ 5,590
Notes payable and commercial paper 1,125 915
Taxes accrued 473 156
Interest accrued 301 310
Current maturities of long-term debt and preferred stock 754 1,331
Unrealized losses on mark-to-market and hedging transactions 2,004 1,918
Other 1,835 1,770
-------- --------
Total current liabilities 13,051 11,990
-------- --------
Long-term Debt 20,480 20,221
-------- --------
Deferred Credits and Other Liabilities
Deferred income taxes 4,813 4,834
Investment tax credit 173 176
Unrealized losses on mark-to-market and hedging transactions 1,443 1,548
Other 4,798 3,784
-------- --------
Total deferred credits and other liabilities 11,227 10,342
-------- --------
Commitments and Contingencies
Guaranteed Preferred Beneficial Interests in Subordinated
Notes of Duke Energy Corporation or Subsidiaries 1,408 1,408
-------- --------
Minority Interests 1,640 1,904
-------- --------
Preferred and Preference Stock
Preferred and preference stock with sinking fund requirements 23 23
Preferred and preference stock without sinking fund requirements 134 134
-------- --------
Total preferred and preference stock 157 157
-------- --------
Common Stockholders' Equity
Common stock, no par, 2 billion shares authorized; 900 million and 895 million
shares outstanding as of March 31, 2003 and December 31, 2002, respectively 9,316 9,236
Retained earnings 6,387 6,417
Accumulated other comprehensive loss (421) (709)
-------- --------
Total common stockholders' equity 15,282 14,944
-------- --------
Total Liabilities and Common Stockholders' Equity $ 63,245 $ 60,966
======== ========
See Notes to Consolidated Financial Statements.
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
Three Months Ended
March 31,
---------------------------
2003 2002
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 225 $ 382
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and amortization (including amortization of nuclear fuel) 484 379
Cumulative effect of changes in accounting principles 162 -
Gain on sales of equity investment (14) (14)
Deferred income taxes (38) (53)
Purchased capacity levelization 47 67
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions (116) 179
Receivables (818) 1,021
Inventory 166 30
Other current assets (183) (200)
Increase (decrease) in
Accounts payable 969 (444)
Taxes accrued 309 176
Other current liabilities 114 (646)
Other, assets (22) 87
Other, liabilities 126 (144)
------------ -------------
Net cash provided by operating activities 1,411 820
------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures, net of cash acquired in acquisitions (635) (1,274)
Investment expenditures (70) (320)
Acquisition of Westcoast Energy Inc., net of cash acquired - (1,690)
Proceeds from the sales of subsidiaries, equity investments and assets 226 23
Notes receivable 80 7
Other 17 (22)
------------ -------------
Net cash used in investing activities (382) (3,276)
------------ -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Issuance of long-term debt 824 2,346
Issuance of common stock and the exercise of stock options 80 77
Payments for the redemption of long-term debt (882) (407)
Net change in notes payable and commercial paper (307) 650
Contributions from minority interests 593 733
Distributions to minority interests (837) (825)
Dividends paid (258) (222)
Other 10 (35)
------------ -------------
Net cash (used in) provided by financing activities (777) 2,317
------------ -------------
Net increase (decrease) in cash and cash equivalents 252 (139)
Cash and cash equivalents at beginning of period 857 290
------------ -------------
Cash and cash equivalents at end of period $ 1,109 $ 151
============ =============
Supplemental Disclosures
Cash paid for interest $ 339 $ 135
Cash (refund from) paid for income taxes $ (73) $ 12
Acquisition of Westcoast Energy Inc.
Fair value of assets acquired $ - $ 9,487
Liabilities assumed, including debt and minority interests - 8,382
Issuance of common stock - 1,797
See Notes to Consolidated Financial Statements.
4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
(In millions)
Three Months Ended
March 31,
------------------------------
2003 2002
------------- -------------
Net Income $ 225 $ 382
Other comprehensive income
Foreign currency translation adjustments 164 (24)
Net unrealized gains on cash flow hedges 258 424
Reclassification into earnings (78) (197)
------------- -------------
Other comprehensive income, before income taxes 344 203
Income tax expense related to items of other comprehensive income (56) (76)
------------- -------------
Total other comprehensive income 288 127
------------- -------------
Total Comprehensive Income $ 513 $ 509
============= =============
See Notes to Consolidated Financial Statements.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), an
integrated provider of energy and energy services, offers physical delivery and
management of both electricity and natural gas throughout the U.S. and abroad.
Duke Energy provides these and other services through the business segments
described below.
Franchised Electric generates, transmits, distributes and sells electricity in
central and western North Carolina and western South Carolina. It conducts
operations primarily through Duke Power and Nantahala Power and Light. These
electric operations are subject to the rules and regulations of the Federal
Energy Regulatory Commission (FERC), the North Carolina Utilities Commission
(NCUC) and the Public Service Commission of South Carolina (PSCSC).
Natural Gas Transmission provides transportation and storage of natural gas for
customers throughout the East Coast and Southern U.S., and in Canada. Natural
Gas Transmission also provides gas sales and distribution service to retail
customers in Ontario and Western Canada, and gas gathering and processing
services to customers in Western Canada. Natural Gas Transmission does business
primarily through Duke Energy Gas Transmission Corporation. Duke Energy Gas
Transmission's natural gas transmission and storage operations in the U.S. are
subject to the FERC's and the Texas Railroad Commission's rules and regulations,
while natural gas gathering, processing, transmission, distribution and storage
operations in Canada are subject to the rules and regulations of the National
Energy Board, the Ontario Energy Board and the British Columbia Utilities
Commission.
Field Services gathers, compresses, treats, processes, transports, trades and
markets, and stores natural gas; and produces, transports, trades and markets,
and stores natural gas liquids. It conducts operations primarily through Duke
Energy Field Services, LLC (DEFS), which is approximately 30% owned by
ConocoPhillips and approximately 70% owned by Duke Energy. Field Services
gathers natural gas from production wellheads in Western Canada and 11
contiguous states in the U.S. Those systems serve major natural gas-producing
regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian
Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well
as onshore and offshore Gulf Coast areas.
Duke Energy North America (DENA) develops, operates and manages merchant power
generation facilities and engages in commodity sales and services related to
natural gas and electric power. DENA conducts business throughout the U.S. and
Canada through Duke Energy North America, LLC and Duke Energy Trading and
Marketing, LLC (DETM). DETM is approximately 40% owned by ExxonMobil Corporation
and approximately 60% owned by Duke Energy. On April 11, 2003, Duke Energy
announced that it will discontinue proprietary trading at DENA.
International Energy develops, operates and manages natural gas transportation
and power generation facilities, and engages in sales and marketing of natural
gas and electric power outside the U.S. and Canada. It conducts operations
primarily through Duke Energy International, LLC and its activities target power
generation in Latin America, power generation and natural gas transmission in
Asia-Pacific, and natural gas marketing in Northwest Europe.
Beginning in 2003, the business segments formally known as Other Energy Services
and Duke Ventures were combined and have been presented as Other Operations.
Other Operations is composed of diverse businesses, operating through Crescent
Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet), Duke Capital
Partners, LLC (DCP), Duke Energy Merchants (DEM), Duke/Fluor Daniel (D/FD) and
Energy Delivery Services (EDS). Crescent develops high-quality commercial,
residential and multi-family real estate projects and manages land holdings
primarily in the Southeastern and Southwestern U.S. DukeNet develops and manages
fiber optic communications systems for wireless, local and long-
6
distance communications companies; and for selected educational, governmental,
financial and health care entities. DCP, a wholly owned merchant finance
company, provides debt and equity capital and financial advisory services
primarily to the energy industry. In March 2003, Duke Energy announced that it
will exit the merchant finance business at DCP in an orderly manner. DEM engages
in commodity buying and selling, and risk management and financial services in
non-regulated energy commodity markets other than physical natural gas and power
(such as petroleum products). On April 11, 2003, Duke Energy announced that it
will also discontinue proprietary trading at DEM. D/FD provides comprehensive
engineering, procurement, construction, commissioning and operating plant
services for fossil-fueled electric power generating facilities worldwide. D/FD
is a 50/50 partnership between Duke Energy 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.
2. Summary of Significant Accounting Policies
Consolidation. The Consolidated Financial Statements include the accounts of
Duke Energy and all majority-owned subsidiaries, after eliminating significant
intercompany transactions and balances. These Consolidated Financial Statements
reflect all normal recurring adjustments that are, in the opinion of management,
necessary to present fairly the financial position and results of operations for
the respective periods. Amounts reported in the interim Consolidated Statements
of Income are not necessarily indicative of amounts expected for the respective
annual periods due to the effects of seasonal temperature variations on energy
consumption, the timing of maintenance on electric generating units and other
factors.
Conformity with generally accepted accounting principles (GAAP) requires
management to make estimates and assumptions that affect the amounts reported in
the financial statements and notes. Although these estimates are based on
management's best available knowledge of current and expected future events,
actual results could be different from those estimates.
Inventory. Inventory, except inventory held for trading, consists primarily of
materials and supplies, natural gas and natural gas liquid products held in
storage for transmission, processing and sales commitments, and coal held for
electric generation. This inventory is recorded at the lower of cost or market
value, primarily using the average cost method. The following table shows the
components of inventory.
- --------------------------------------------------------------------------------
Inventory (in millions)
- --------------------------------------------------------------------------------
March 31, December 31,
2003 2002
- --------------------------------------------------------------------------------
Materials and supplies $757 $ 873
Petroleum products 56 83
Coal 77 77
Gas stored underground 43 71
Trading mark to market inventory - 16
Gas used in operations 13 14
-----------------------------
Total inventory $946 $1,134
- --------------------------------------------------------------------------------
Earnings Per Common Share. Basic earnings per share are based on a weighted
average of common shares outstanding. Diluted earnings per share reflect the
potential dilution that could occur if securities or other agreements to issue
common stock, such as stock options, stock-based performance unit awards and
phantom stock awards, were exercised or converted into common stock. The
numerator for the calculation of both basic and diluted earnings per share is
earnings available for common stockholders. The following table shows the
denominator for basic and diluted earnings per share.
7
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Denominator for Earnings per Share (in millions)
- ------------------------------------------------------------------------
Three Months Ended
March 31,
-------------------
2003 2002
-------------------
Denominator for basic earnings per share
(weighted average shares outstanding)/a/ 896.7 787.7
Assumed exercise of dilutive securities or
other agreements to issue common stock 0.5 3.9
-------------------
Denominator for diluted earnings per share 897.2 791.6
========================================================================
/a/ Increase in weighted-average shares from 2002 to 2003 is due primarily to
the acquisition of Westcoast Energy Inc. on March 14, 2002 and the October 2002
equity issuance of 54.5 million shares.
Options to purchase approximately 30 million shares of common stock as of March
31, 2003, and 18 million shares as of March 31, 2002, were not included in the
computation of diluted earnings per share because the option exercise prices
were greater than the average market price of the common shares during those
periods.
Accounting for Risk Management and Trading Activities. All derivatives not
qualifying for the normal purchases and sales exemption under Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," are recorded on the Consolidated Balance
Sheets at their fair value as Unrealized Gains or Unrealized Losses on
Mark-to-Market and Hedging Transactions. Prior to the implementation of the
remaining provisions of Emerging Issues Task Force (EITF) Issue No. 02-03,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and for Contracts Involved in Energy Trading and Risk Management
Activities" on January 1, 2003, certain non-derivative energy trading contracts
were also recorded on the Consolidated Balance Sheets at their fair value as
Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. See the Cumulative Effect of Changes in Accounting Principles
section below for further discussion of the implementation of the provisions of
EITF Issue No. 02-03.
Effective January 1, 2003, in connection with the implementation of the
remaining provisions of EITF Issue No. 02-03, Duke Energy designates each energy
commodity derivative as either trading or non-trading. Certain non-trading
derivatives are further designated as either a hedge of a forecasted transaction
or future cash flows (cash flow hedge), a hedge of a recognized asset, liability
or firm commitment (fair value hedge), or a normal purchase or sale contract,
while certain non-trading derivatives remain undesignated. Derivatives related
to marketing and other risk management activities are designated as non-trading.
Derivatives designated as trading primarily relate to Duke Energy's proprietary
trading activities. As discussed above, Duke Energy has announced it is
discontinuing proprietary trading at DENA (see Note 1.)
Duke Energy accounts for both trading and undesignated non-trading derivatives
using the mark-to-market accounting method and uses the accrual method for its
other derivatives. EITF Issue No. 02-03 requires realized and unrealized gains
and losses on all derivative instruments designated as trading to be shown on a
net basis in the income statement, but does not provide guidance on the income
statement presentation of gains and losses on non-trading derivatives. EITF
Issue No. 02-L, "Reporting Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, and Not Held for Trading Purposes," is currently an open
issue for the EITF and any consensus reached on this issue may require changes
in Duke Energy's presentation of non-trading gains and losses. Gains and losses
on non-derivative energy trading contracts are presented on a gross or net basis
in connection with the guidance in EITF Issue No. 99-19, "Reporting Revenue
Gross as a Principal vs. Net as an Agent."
8
For each of the non-trading derivative categories identified above, Duke Energy
reports gains and losses in the Consolidated Statements of Income as follows:
. Gains and losses relating to non-trading derivatives designated as
cash flow or fair value hedges are reported on a gross basis, upon
settlement, in the same income statement category as the related
hedged item.
. Gains and losses relating to normal purchase or sale contracts are
reported on a gross basis upon settlement.
. Gains and losses from undesignated non-trading physical derivatives
that are entered into and settled during the same month, which
primarily relate to Duke Energy's natural gas wholesale marketing
operations, are reported on a gross basis.
. Gains and losses from all other undesignated non-trading derivatives
are reported on a net basis in Trading and Marketing Net Margin.
Prior to January 1, 2003, unrealized and realized gains and losses on all energy
trading contracts, as defined in EITF Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," which included many
derivative and non-derivative instruments, were presented on a net basis in
Trading and Marketing Net Margin in the Consolidated Statements of Income. While
the income statement presentation of gains and losses for each category of
non-trading derivatives, as described above, remained consistent from 2002 to
2003, the definition of a trading and non-trading instrument changed from EITF
Issue No. 98-10 to EITF Issue No. 02-03. Under EITF Issue No. 98-10, all energy
derivative and non-derivative contracts were considered to be trading that were
entered into by an entity's energy trading operations, while under EITF Issue
No. 02-03 an assessment is performed for each contract and only those individual
derivative contracts that are entered into with the intent of generating profits
on short-term differences in price are considered to be trading. As a result, a
significant number of derivatives previously classified as trading under EITF
Issue No. 98-10 became classified as non-trading as of January 1, 2003.
Other Current Liabilities. Through master collateral agreements, counterparties
must post cash collateral to Duke Energy and its affiliates for exposure in
excess of a contractual threshold. The receipt of cash by Duke Energy creates a
current liability on the Consolidated Balance Sheets for the amount received.
The amount of this current liability was approximately $650 million as of March
31, 2003 and approximately $355 million as of December 31, 2002 and is included
in Other Current Liabilities on the Consolidated Balance Sheets.
Goodwill. The following table shows the changes in the carrying amount of
goodwill for the three months ended March 31, 2003.
- -------------------------------------------------------------------------------------
GOODWILL (in millions)
- -------------------------------------------------------------------------------------
Balance Balance
December 31, 2002 Other/a/ March 31, 2003
------------------------------------------------------
Natural Gas Transmission $ 2,760 $ (20) $2,740
Field Services 481 4 485
Duke Energy North America 100 - 100
International Energy 246 (1) 245
Other Operations 6 - 6
Other 154 - 154
------------------------------------------------------
Total consolidated $ 3,747 $(17) $3,730
- -------------------------------------------------------------------------------------
/a/ Amounts consist primarily of foreign currency adjustments and purchase price
adjustments to prior year acquisitions.
9
Guarantees. Duke Energy accounts for guarantees and related contracts, for which
it is the guarantor, under Financial Accounting Standards Board (FASB)
Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others." In accordance with FIN 45, upon issuance or modification of a guarantee
on or after January 1, 2003, Duke Energy recognizes a liability at the estimated
fair value of the obligation it assumes under that guarantee. Duke Energy
relieves the obligation over the term of the guarantee or related contract in a
systematic and rational method. Any additional contingent loss for guarantee
contracts is accounted for and recognized in accordance with SFAS No. 5,
"Accounting for Contingencies."
Stock-Based Compensation. Duke Energy accounts for its stock-based compensation
arrangements under the intrinsic value recognition and measurement principles of
Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued
to Employees," and FASB Interpretation No. 44, "Accounting for Certain
Transactions Involving Stock Compensation (an Interpretation of APB Opinion No.
25)." Since the exercise price for all options granted under those plans was
equal to the market value of the underlying common stock on the date of grant,
no compensation cost is recognized in the accompanying Consolidated Statements
of Income. Restricted stock grants, phantom stock awards and stock-based
performance awards are recorded over the required vesting period as compensation
cost, based on the market value on the grant date.
The following table shows what earnings available for common stockholders,
earnings per share and diluted earnings per share would have been if Duke Energy
had applied the fair value recognition provisions of SFAS No. 123, "Accounting
for Stock-Based Compensation," to all stock-based compensation awards.
======================================================================
Pro Forma Stock-Based Compensation
(in millions, except per share amounts)
- ----------------------------------------------------------------------
Three Months Ended
March 31,
------------------------
2003 2002
------------------------
Earnings available for common
stockholders, as reported $222 $379
Add: stock-based compensation
expense included in reported net
income, net of related tax effects 2 3
Deduct: total stock-based
compensation expense determined
under fair value-based method for all
awards, net of related tax effects (7) (44)
------------------------
Pro forma earnings available for common
stockholders, net of related tax effects $217 $338
------------------------
Earnings per share
Basic - as reported $0.25 $0.48
Basic - pro forma $0.24 $0.43
Diluted - as reported $0.25 $0.48
Diluted - pro forma $0.24 $0.43
======================================================================
10
Accumulated Other Comprehensive Loss. The following table shows the components
of and changes in accumulated other comprehensive loss.
========================================================================================================
Accumulated Other Comprehensive Loss (in millions)
- --------------------------------------------------------------------------------------------------------
Net Accumulated
Foreign Unrealized Minimum Pension Other
Currency Gains on Cash Liability Comprehensive
Adjustments Flow Hedges Adjustment Loss
---------------------------------------------------------------
Balance as of December 31, 2002 $(647) $422 $(484) $(709)
Other comprehensive income changes
during the quarter (net of taxes
of $56) 164 124 - 288
---------------------------------------------------------------
Balance as of March 31, 2003 $(483) $546 $(484) $(421)
========================================================================================================
Cumulative Effect of Change in Accounting Principles. As of January 1, 2003,
Duke Energy adopted the remaining provisions of EITF Issue No. 02-03 and SFAS
No. 143, "Accounting for Asset Retirement Obligations." In accordance with the
transition guidance for these standards, Duke Energy recorded a net-of-tax and
minority interest cumulative effect adjustment for change in accounting
principles of $162 million, or $0.18 per basic share, as a reduction in
earnings. See additional discussion of the cumulative effect adjustments below.
In October 2002, the EITF reached a final consensus on EITF Issue No. 02-03.
Primarily, the final consensus provided for (1) the rescission of the consensus
reached on EITF Issue No. 98-10, (2) the reporting of gains and losses on all
derivative instruments considered to be held for trading purposes to be shown on
a net basis in the income statement, and (3) gains and losses on non-derivative
energy trading contracts to be similarly presented on a gross or net basis, in
connection with the guidance in EITF Issue No. 99-19.
As a result of the consensus on EITF Issue No. 02-03, all non-derivative energy
trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that
existed on October 25, 2002 and inventories that were recorded at fair values
have been adjusted to historical cost via a cumulative effect adjustment of $151
million (net of tax and minority interest) that reduced first quarter 2003
earnings. Adopting the final consensus on EITF Issue No. 02-03 did not require a
change to prior periods and, therefore, Duke Energy did not change the 2002
classification of operating revenue and operating expense amounts.
In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. The standard applies
to legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal use of the
asset. For obligations related to non-regulated operations, a cumulative effect
adjustment of $11 million (net of tax and minority interest) was recorded in the
first quarter of 2003, as a reduction in earnings. (For a full discussion of
asset retirement obligations, see Note 6.)
New Accounting Standards. SFAS No. 146, "Accounting for Costs Associated with
Exit or Disposal Activities." In June 2002, the FASB issued SFAS No. 146 which
addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Duke
Energy has adopted the provisions of SFAS No. 146 for restructuring activities
initiated after December 31, 2002. SFAS No. 146 requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost
was recognized on the date of Duke Energy's commitment to an exit plan. SFAS No.
146 also establishes that the liability should initially be measured and
recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of
recognizing future restructuring costs as well as the amounts recognized.
11
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." In April 2003, the FASB issued SFAS No. 149, which amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. SFAS No. 149 clarifies the discussion around initial net investment and
when a derivative contains a financing component, and amends the definition of
the term underlying to conform it to language used in FIN 45. In addition, SFAS
No. 149 also incorporates certain Derivative Implementation Group Implementation
Issues. The provisions of SFAS No. 149 are effective for contracts entered into
or modified after June 30, 2003, and for hedging relationships designated after
June 30, 2003. The guidance should be applied to hedging relationships on a
prospective basis. Duke Energy is currently assessing the impact SFAS No. 149
will have on its consolidated results of operations, cash flows and financial
position.
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities." In January 2003, the FASB issued FIN 46 which requires the primary
beneficiary of a variable interest entity's activities to consolidate the
variable interest entity. The primary beneficiary is the party that absorbs a
majority of the expected losses and/or receives a majority of the expected
residual returns of the variable interest entity's activities. FIN 46 is
immediately applicable to variable interest entities created, or interests in
variable interest entities obtained, after January 31, 2003. For variable
interest entities created, or interests in variable interest entities obtained,
on or before January 31, 2003, FIN 46 is required to be applied in the first
fiscal year or interim period beginning after June 15, 2003. FIN 46 may be
applied prospectively with a cumulative-effect adjustment as of the date it is
first applied, or by restating previously issued financial statements with a
cumulative-effect adjustment as of the beginning of the first year restated. FIN
46 also requires certain disclosures of an entity's relationship with variable
interest entities. Duke Energy has not identified any variable interest entities
created, or interests in variable entities obtained, after January 31, 2003 and
continues to assess the existence of any interests in variable interest entities
created on or prior to January 31, 2003. It is reasonably possible that Duke
Energy will disclose information about a variable interest entity upon the
application of FIN 46, primarily as the result of investments it has in certain
unconsolidated affiliates. Any significant exposure to losses related to these
entities would be related to guarantee obligations as discussed in Note 9. Duke
Energy continues to assess FIN 46 but does not anticipate that it will have a
material impact on its consolidated results of operations, cash flows or
financial position.
Reclassifications. Certain prior period amounts have been reclassified to
conform to current classifications.
3. Business Acquisitions
Duke Energy consolidates assets and liabilities from acquisitions as of the
purchase date, and includes earnings from acquisitions in consolidated earnings
after the purchase date. Assets acquired and liabilities assumed are recorded at
estimated fair values on the date of acquisition. The purchase price minus the
estimated fair value of the acquired assets and liabilities is recorded as
goodwill. The allocation of the purchase price may be adjusted if additional
information on asset and liability valuations becomes available within one year
after the acquisition.
On March 14, 2002, Duke Energy acquired Westcoast Energy Inc (Westcoast) for
approximately $8 billion, including the assumption of $4.7 billion of debt. The
Westcoast acquisition was accounted for using the purchase method, and goodwill
of approximately $2.3 billion was recorded in the transaction, of which
approximately $57 million is expected to be deductible for income tax purposes.
Of the $57 million, $52 million was allocated for tax purposes to Empire State
Pipeline which was sold in February 2003.
During the first quarter of 2003, Duke Energy recorded additional purchase price
adjustments as information regarding the assets acquired became available,
including adjustments related to the sale of Empire State Pipeline to National
Fuel Gas Company. The purchase price amounts in the following table reflect the
additional purchase price adjustments and the adjustments for the sale of Empire
State Pipeline.
12
The following table summarizes the estimated fair values of the assets acquired
and liabilities assumed as of the acquisition date.
============================================================================
Purchase Price Allocation for Westcoast Acquisition (in millions)
- ----------------------------------------------------------------------------
Current assets $ 2,050
Investments and other assets 1,207
Goodwill 2,253
Property, plant and equipment 4,991
Regulatory assets and deferred debits 809
------------------
Total assets acquired 11,310
------------------
Current liabilities 1,655
Long-term debt 4,132
Deferred credits and other liabilities 1,662
Minority interests 560
------------------
Total liabilities assumed 8,009
------------------
Net assets acquired $ 3,301
============================================================================
Operating revenues would have been $3,626 million, earnings available for common
stockholders would have been $416 million, and basic and dilutive earnings per
share would have been $0.50 for the period ended March 31, 2002 if the Westcoast
acquisition had taken place at the beginning of the period ended March 31, 2002.
4. Business Segments
Duke Energy's reportable segments offer different products and services and are
managed separately as business units. Accounting policies for Duke Energy's
segments are the same as those described in Note 2. Management evaluates segment
performance primarily based on earnings before interest and taxes (EBIT) after
deducting minority interests. The following table shows how consolidated EBIT is
calculated before deducting minority interests.
===========================================================================
Reconciliation of Operating Income to EBIT (in millions)
- ---------------------------------------------------------------------------
Three Months Ended
March 31,
-----------------------------
2003 2002
-----------------------------
Operating income $893 $668
Other income and expenses 81 102
-----------------------------
EBIT $974 $770
===========================================================================
EBIT may be viewed as a non-GAAP measure under the rules of the Securities and
Exchange Commission (SEC). Duke Energy has included EBIT in its disclosures
because it is the primary performance measure used by management to evaluate
total company and segment performance. On a segment basis, it includes all
profits (both operating and non-operating) before deducting interest and taxes,
and is net of the minority interest expense related to those profits. Management
believes EBIT is a good indicator of each segment's operating performance, as it
represents the results of Duke Energy's ownership interests in operations
without regard to financing methods or capital structure. As an indicator of
Duke Energy's operating performance, EBIT should not be considered an
alternative to, or more meaningful than, net income or cash flow as determined
in accordance with GAAP. Duke Energy's EBIT may not be comparable to a similarly
titled measure of another company because other entities may not calculate EBIT
in the same manner.
13
Cash and cash equivalents are managed centrally by Duke Energy. Since the
business units do not manage these items, the gains and losses on foreign
currency remeasurement associated with such cash balances and third party
interest income on these balances are excluded from the segments' EBIT.
In the accompanying table, EBIT includes the profit on intersegment sales at
prices management believes are representative of arms' length transactions. The
line item "Other" primarily includes certain unallocated corporate costs.
=========================================================================================================
Business Segment Data (in millions)
- ---------------------------------------------------------------------------------------------------------
Capital
Depreciation and
Unaffiliated Intersegment Total and Investment
Revenues Revenues Revenues EBIT Amortization Expenditures
---------------------------------------------------------------------------
Three Months Ended
March 31, 2003
Franchised Electric $1,247 $ 4 $1,251 $454 $179 $ 176
Natural Gas Transmission 879 89 968 423 96 198
Field Services 2,004 468 2,472 33 78 31
Duke Energy North America 1,308 88 1,396 23 57 160
International Energy 382 - 382 54 25 25
Other Operations 504 52 556 (26) 11 69
Other - 2 2 (31) 3 46
Eliminations and
minority interests - (703) (703) 46 - -
Third party interest income - - - 3 - -
Foreign currency loss - - - (5) - -
------------------------------------------------------------------------
Total consolidated $6,324 $ - $6,324 $974 $449 $ 705
- ------------------------------------------------------------------------------------------------------
Three Months Ended
March 31, 2002
Franchised Electric $1,113 $ - $1,113 $384 $153 $ 244
Natural Gas Transmission 422 28 450 266 54 2,020
Field Services 933 201 1,134 35 74 110
Duke Energy North America 443 (185) 258 54 29 736
International Energy 287 2 289 57 23 81
Other Operations 110 78 188 17 8 134
Other - (3) (3) (107) 3 36
Eliminations and
minority interests - (121) (121) 14 - -
Third party interest income - - - 41 - -
Foreign currency gain - - - 9 - -
Cash acquired in acquisitions - - - - - (77)
------------------------------------------------------------------------
Total consolidated $3,308 $ - $3,308 $770 $344 $ 3,284
- ------------------------------------------------------------------------------------------------------
14
Segment assets in the accompanying table are net of intercompany advances,
intercompany notes receivable, intercompany current assets, intercompany
derivative assets and investments in subsidiaries.
==============================================================
Segment Assets (in millions)
- --------------------------------------------------------------
March 31, December 31,
2003 2002
-----------------------------
Franchised Electric $14,358 $13,503
Natural Gas Transmission 16,049 15,168
Field Services 7,540 6,827
Duke Energy North America 16,770 15,457
International Energy 5,778 5,803
Other Operations 2,901 3,117
Other, net of eliminations (151) 1,091
-----------------------------
Total consolidated $63,245 $60,966
==============================================================
5. Regulatory Matters
Regulatory Assets and Liabilities. In the first quarter of 2003, Duke Energy
adopted SFAS No. 143, which applies to legal obligations associated with the
retirement of tangible long-lived assets and the related asset retirement costs
(see Note 6). Certain of Duke Energy's regulated operations recognize some
removal costs as a component of accumulated depreciation for property that does
not have an associated legal retirement obligation, in accordance with
regulatory treatment. As of March 31, 2003, the amount of accumulated
depreciation on the Consolidated Balance Sheet related to this regulatory
liability was approximately $915 million, excluding the internal reserve for
nuclear decommissioning of $250 million.
Franchised Electric. On January 14, 2003, the PSCSC decided to conduct an
independent management audit of Duke Power's preventive maintenance programs and
service restoration procedures for its South Carolina retail electric service
area in connection with a winter storm in December 2002. The PSCSC issued a
request for proposal on March 11, 2003, seeking an independent firm or
individual to perform the management audit on its behalf. Duke Energy will
cooperate with the PSCSC in this audit. Management believes that the final
disposition of this matter will have no material adverse effect on consolidated
results of operations, cash flows or financial position.
Franchised Electric's amortization expense for the quarter ended March 31, 2003
included $17 million related to North Carolina's 2002 clean air legislation.
This legislation requires electric utilities, including Duke Energy to reduce
emissions of sulfur dioxide and nitrogen oxides from the state's coal fired
power plants over the next 10 years and includes provisions that allow electric
utilities to accelerate the recovery of these compliance costs by amortizing
them over seven years. (See Note 16 to the Consolidated Financial Statements,
"Commitments and Contingencies - Environmental, Air Quality Control," in Duke
Energy's Form 10-K for December 31, 2002 for additional information on this
matter.)
Notices of Proposed Rulemaking (NOPR). NOPR on Standard Market Design. In July
2002, the FERC approved a NOPR entitled Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design
(Standard Market Design or SMD). The FERC has proposed to modify the open access
transmission tariff and implement an SMD that would apply to Regional
Transmission Organizations (RTOs) and to individual utilities that have not yet
joined an RTO. The FERC proposes to require each transmission owner to give an
Independent Transmission Provider (ITP) operational control over the
transmission owner's facilities. These ITPs will file SMD tariffs for
transmission and ancillary services, administer day-ahead and real-time markets,
monitor and mitigate market power, perform long-term resource adequacy and
participate in transmission planning and expansion on a regional basis.
Duke Energy filed comments on certain aspects of the NOPR in November 2002, and
again in January 2003. The NOPR contemplates implementation of SMD by 2004,
although there are indications that the
15
FERC expects the implementation timetable to be delayed. A FERC White Paper
issued on April 28, 2003 reflects filed comments and testimony presented at
technical conferences, and recognizes the strong criticism of the SMD NOPR by
some state regulators, industry interests and members of Congress. The White
Paper now envisions a "Wholesale Market Platform" in which transmission provider
membership in an RTO is mandatory, rather than voluntary as in the FERC's
previous orders. The White Paper also discusses a series of changes to the NOPR
signaling flexibility on the part of the FERC in the implementation of new
market rules. Duke Energy is reviewing the White Paper to determine an
appropriate response. No date for the final rule has been set.
NOPR on Hydroelectric Licensing. In February 2003, the FERC issued a NOPR
proposing revised hydroelectric licensing regulations under the Federal Power
Act. The revisions would create a new integrated licensing process (ILP) in
which pre-filing consultation and the FERC's scoping pursuant to the National
Environmental Policy Act (NEPA) would be conducted concurrently, rather than
sequentially. The two existing licensing processes would be preserved as
options, but the ILP would be the default process, unless the license applicant
showed good cause and gained FERC approval to use one of the existing options.
The proposed rules also provide for increased public participation in pre-filing
consultation; development by the potential applicant of a FERC-approved study
plan; better coordination between FERC processes, including NEPA document
preparation, and with other Federal and state agencies with authority to require
conditions for FERC-issued licenses; encouragement of informal resolution of
study disagreements, followed by mandatory, binding study dispute resolution;
and schedules and deadlines. Duke Energy has determined that the proposed
changes will not impact the hydro re-licensing process currently underway,
although application requirements for new licenses may change. Duke Energy
recognizes the benefits of the proposed changes, but remains concerned about
issues of fair participation among license applicants and resource agencies.
Duke Power filed comments with the FERC on the NOPR in April 2003. The FERC is
expected to hold redrafting workshops later in the spring of 2003 and to issue a
revised proposal in July 2003, with expectations that the final rule will be
implemented in the fall of 2003.
6. Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. The standard applies
to legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal use of the
asset. Asset retirement obligations at Duke Energy relate primarily to the
decommissioning of nuclear power facilities, the retirement of certain gathering
pipelines and processing facilities, the retirement of some gas-fired power
plants, obligations related to right-of-way agreements and contractual leases
for land use.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability increases due to the
passage of time based on the time value of money until the obligation is
settled.
In accordance with SFAS No. 143, Duke Energy identified certain assets that have
an indeterminate life, and thus a future retirement obligation is not
determinable. These assets included on-shore and some off-shore pipelines,
certain processing plants and distribution facilities and some gas-fired power
plants. A liability for these asset retirement obligations will be recorded when
a fair value is determinable.
Certain of Duke Energy's regulated operations recognize some removal costs as a
component of depreciation in accordance with regulatory treatment. While these
amounts will remain in accumulated depreciation, to the extent they do not
represent SFAS No. 143 legal retirement obligations, they are disclosed as part
of the regulatory matters footnote (see Note 5).
SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and
was adopted by Duke Energy on January 1, 2003. As of January 1, 2003, the
implementation of SFAS No. 143 resulted in a net
16
increase in total assets of $863 million, consisting primarily of an increase in
net property, plant and equipment of $214 million and an increase in regulatory
assets of $650 million. Liabilities increased by $874 million, primarily
representing the establishment of an asset retirement obligation liability of
$1,599 million, reduced by the amount that was already recorded as a nuclear
decommissioning liability of $708 million. Substantially all of the obligations
are related to Duke Energy's regulated electric operations. The adoption of SFAS
No. 143 had no impact on the income of the regulated electric operations, as the
effects were offset by the establishment of a regulatory asset and regulatory
liability pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types
of Regulation." Duke Energy filed a request on January 10, 2003 with the NCUC to
defer the income statement effect of adopting SFAS No.143 for its regulated
electric operations. The NCUC approved the deferral of the cumulative income
statement impact for the implementation of SFAS No. 143, but denied the deferral
of the future expenses because Duke Energy did not quantify the amount. Duke
Energy intends to seek the NCUC'S reconsideration of the treatment of the future
expenses. In April 2003, Duke Energy received approval from the PSCSC to defer
all cumulative and future income statement impacts related to SFAS No. 143. For
obligations related to non-regulated operations, a net-of-tax cumulative effect
of a change in accounting principle adjustment of $11 million was recorded in
the first quarter of 2003 as a reduction in earnings. As of March 31, 2003, Duke
Energy had $712 million of assets that are legally restricted for the purpose of
settling asset retirement obligations.
The following table shows the asset retirement obligation liability as though
SFAS No. 143 had been in effect for the three prior years.
======================================================================
Pro forma Asset Retirement Obligation Liability (in millions)
- ----------------------------------------------------------------------
January 1, 2000 $1,267
December 31, 2000 1,374
December 31, 2001 1,476
December 31, 2002 1,599
======================================================================
The pro forma net income and related basic and diluted earnings per share
effects of adopting SFAS No. 143 are not shown due to their immaterial impact.
The asset retirement obligation is adjusted each quarter for any liabilities
incurred or settled during the period, accretion expense and any revisions made
to the estimated cash flows. The following table shows the reconciliation of the
asset retirement obligation liability for the quarter ended March 31, 2003.
=============================================================================================
Reconciliation of Asset Retirement Obligation Liability for the Quarter Ended March 31, 2003
(in millions)
- ---------------------------------------------------------------------------------------------
Balance as of January 1, 2003 $1,599
Accretion expense 28
Other (3)
----------------
Balance as of March 31, 2003 $1,624
=============================================================================================
Of the $28 million in accretion expense for the quarter ended March 31, 2003,
approximately $26 million relates to Duke Energy's regulated electric operations
and has been deferred in accordance with SFAS No. 71 as discussed above.
7. Debt and Credit Facilities
In February 2003, Duke Energy issued $500 million of 3.75% first and refunding
mortgage bonds due in 2008 in a private placement transaction exempt from
registration under Rule 144A of the Securities Act of 1933, as amended
(Securities Act). The bonds are subject to a registration agreement, whereby
Duke Energy has agreed to register an exchange with the holders of identical
bonds under the Securities Act. The proceeds from this issuance were used to
repay short-term debt, to replace $100 million of Duke Energy's first and
refunding mortgage bonds that matured in February 2003, to repay approximately
$200 million of an intercompany loan from Duke Capital Corporation (a wholly
owned subsidiary of Duke Energy that provides financing and credit enhancement
services for its subsidiaries) and for general corporate purposes.
In March 2003, Duke Energy issued $200 million of 4.50% first and refunding
mortgage bonds due in 2010. The proceeds from this issuance were used to repay
commercial paper and for general corporate purposes.
17
In the first quarter of 2003, $500 million of Duke Capital Corporation
commercial paper that had been included in Long-term Debt on the December 31,
2002 Consolidated Balance Sheet was reclassified on the March 31, 2003
Consolidated Balance Sheet to Notes Payable and Commercial Paper. This
reclassification reflects Duke Energy's intention to no longer maintain an
outstanding long-term portion of commercial paper at Duke Capital Corporation.
In March 2003, DEFS entered into a $100 million funded short-term loan with Bank
One, NA. This short-term loan matures in September 2003, and may be prepaid at
any time. This short-term loan has an interest rate equal to, at DEFS' option,
either (1) the London Interbank Offered Rate plus 1.35% per year or (2) the
higher of (a) the Bank One, NA prime rate and (b) the Federal Funds rate plus
0.50% per year. DEFS does not plan to refinance this short-term loan when it
matures.
Also in March 2003, DEFS closed a 364-day syndicated bank credit facility for
$350 million to replace an expiring syndicated bank credit facility.
In March 2003, a wholly owned subsidiary of Duke Energy, Duke Australia Finance
Pty Ltd. closed a syndicated bank credit facility for 315 million Australian
dollars (U.S. $190 million) to replace a syndicated bank credit facility that
expired.
In May 2003, Duke Energy completed an offering of $700 million of 1.75%
convertible senior notes due in 2023. These senior notes are convertible to Duke
Energy common stock at a premium of 40% above the May 1, 2003 closing common
stock market price of $16.85 per share. The conversion of these senior notes
into shares of Duke Energy common stock is contingent on certain events during
specified periods. In connection with the offering, Duke Energy granted the
underwriters an option to purchase an additional $70 million of convertible
senior notes to cover any over allotments. The net proceeds of the offering will
be used for general corporate purposes, which will include the reduction of
outstanding commercial paper.
18
The following table summarizes Duke Energy's credit facilities and related
amounts outstanding as of March 31, 2003. The majority of the credit facilities
support commercial paper programs. The issuance of commercial paper, letters of
credit and other borrowings reduces the amount available under the credit
facilities.
=======================================================================================================================
Credit Facilities Summary as of March 31, 2003 (in millions)
- -----------------------------------------------------------------------------------------------------------------------
Amounts Outstanding
-----------------------------------------------
Credit
Expiration Facilities Commercial Letters of Other
Date Available Paper Credit Borrowings Total
------------ ----------- ------------ ------------ ------------ --------
Duke Energy
- -----------
$475 364-Day syndicated /a/, /b/ August 2003
$475 Multi-year syndicated /a/, /b/ August 2004
Total Duke Energy
$ 950 $ 516 $ - $ - $ 516
Duke Capital Corporation
- ------------------------
$500 Temporary bilateral /b/, /c/ June 2003
$700 364-Day syndicated /a/, /b/, /c/ August 2003
$500 364-Day syndicated letter of credit /a/,
/b/, /c/, /d/ April 2003
$142 364-Day bilateral /a/, /b/, /c/ August 2003
$550 Multi-year syndicated /a/, /b/, /c/ August 2004
$538 Multi-year syndicated letter of credit
/b/, /c/ April 2004
Total Duke Capital Corporation 2,930 679 517 - 1,196
Westcoast Energy Inc.
- ---------------------
$171 364-Day syndicated /a/, /b/ December 2003
$136 Two-year syndicated /b/ December 2004
Total Westcoast Energy Inc. /e/ 307 23 - - 23
Union Gas Limited
- -----------------
$409 364-Day syndicated /f/ July 2003 409 - - - -
Duke Energy Field Services, LLC
- -------------------------------
$350 364-Day syndicated /a/, /c/, /g/ March 2004 350 84 - - 84
Duke Australia Finance Pty Ltd.
- -------------------------------
$190 364-Day syndicated /h/ March 2004 190 - - - -
Duke Australia Pipeline Finance Pty Ltd.
- ----------------------------------------
$188 Multi-year syndicated /i/ February 2005 188 134 - 209 343
----------------------------------------------------------
Total $ 5,324 $1,436 $ 517 $ 209 $2,162
=======================================================================================================================
/a/ Credit facility contains an option allowing borrowing up to the full amount
of the facility on the day of initial expiration for up to one year.
/b/ Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 65%.
/c/ Credit facility contains an interest coverage covenant of two and a half
times or greater.
/d/ In April 2003, credit facility matured and was replaced with a $253 million
364-day syndicated letter of credit facility with an April 2004 expiration.
/e/ Credit facilities are denominated in Canadian dollars, and totaled 450
million Canadian dollars as of March 31, 2003.
/f/ Credit facility contains an option allowing up to 50% of the amount of the
facility to be borrowed on the day of initial expiration for up to one
year. Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 75%. Credit facility is denominated in
Canadian dollars, and was 600 million Canadian dollars as of March 31,
2003.
/g/ Credit facility contains a covenant requiring the debt to total
capitalization ratio to not exceed 53%.
/h/ Credit facility is guaranteed by Duke Capital Corporation. Credit facility
is denominated in Australian dollars, and was 315 million Australian
dollars as of March 31, 2003.
/i/ Credit facility is guaranteed by Duke Capital Corporation. Credit facility
is denominated in Australian dollars, and totaled 312 million Australian
dollars as of March 31, 2003. Duke Australia Pipeline Finance Pty Ltd. is a
wholly owned subsidiary of Duke Energy.
19
In addition to the existing bank credit facilities, Duke Capital Corporation has
a separate option to borrow up to $250 million between June 30, 2003 and August
29, 2003. Any amounts borrowed under this option would be due no later than
March 31, 2004. Also, Duke Capital Corporation is currently maintaining a
minimum cash position of $500 million to be used for short-term liquidity needs.
This cash position is invested in highly rated, liquid, short-term money market
securities.
As of March 31, 2003, Duke Energy has approximately $2,900 million of credit
facilities which mature in 2003. It is Duke Energy's intent to significantly
reduce its need for these facilities as the year progresses and thus resyndicate
less than the total $2,900 million.
Duke Energy's credit agreements contain various financial and other covenants.
Failure to meet those covenants beyond applicable grace periods could result in
acceleration of due dates of certain borrowings and/or termination of the
agreements. As of March 31, 2003, Duke Energy was in compliance with those
covenants. In addition, certain of the agreements contain cross-acceleration
provisions that may allow acceleration of payments or termination of the
agreements upon nonpayment or acceleration of other significant indebtedness of
the applicable borrower or certain of its subsidiaries.
As of March 31, 2003, Duke Energy and its subsidiaries had effective SEC shelf
registrations for up to $2,300 million in gross proceeds from debt and other
securities. Subsequent to March 31, 2003, these SEC shelf registrations have
been reduced by $700 million for the convertible senior notes issued in May
2003. Related to this issuance, the underwriters may exercise their option to
purchase an additional $70 million of these notes, which would further reduce
shelf availability. As of March 31, 2003, Duke Energy also had access to 950
million Canadian dollars (U.S. $648 million) available under Canadian shelf
registrations for issuances in the Canadian market.
8. Commitments and Contingencies
Litigation
Western Power Disputes. Several investigations and regulatory proceedings at the
state and federal levels are looking into the causes of high wholesale
electricity prices in the western U.S. during 2000 and 2001. As a result, the
FERC has ordered some sellers, including DETM, to refund, or to offset against
outstanding accounts receivable, amounts billed for electricity sales in excess
of a FERC-established proxy price. In December 2002, the presiding
administrative law judge in the FERC refund proceedings issued his proposed
findings with respect to the mitigated market clearing price, including his
preliminary determinations of the refund liability of each seller of electricity
in the California Independent System Operator (CAISO) and the California Power
Exchange (CalPX). These proposed findings estimated that DETM has refund
liability of approximately $95 million in the aggregate to both the CAISO and
CalPX. This would be offset against the remaining receivables still owed to DETM
by the CAISO and CalPX. The proposed findings were the presiding judge's
estimates only, and are subject to further recalculation and adoption by the
FERC in connection with its ongoing wholesale pricing investigation. (See Note
16 to the Consolidated Financial Statements, "Commitments and Contingencies -
Litigation, Western Power Disputes, Other Proceedings," in Duke Energy's Form
10-K for December 31, 2002 for additional information on these matters.) On
March 3, 2003, various parties (including the California attorney general) filed
at the FERC seeking modification of the FERC's refund orders and alleging that
DETM and others manipulated wholesale electricity prices in periods prior to the
initial refund period. DETM filed responses denying the California parties'
allegations.
On March 26, 2003, the FERC issued staff recommendations relating to the FERC's
investigation into the causes of high wholesale electricity prices in the
Western U.S. during 2000 and 2001, and an order in the FERC's refund proceeding.
The recommendations and order address, among other things: modifying the
presiding judge's refund findings with respect to the gas price component and
certain other components of the refund calculation; issuance of show cause
orders related to certain energy trading practices; requiring trading entities
to demonstrate that they have corrected their internal processes for reporting
trading data to the Trade Press in order to continue selling natural gas at
wholesale (see "Trading Matters" below); and
20
establishing a ban on prearranged "round trip" trades as a condition of blanket
certificates (see Note 16 to the Consolidated Financial Statements, "Commitments
and Contingencies - Litigation, Trading Matters," in Duke Energy's Form 10-K for
December 31, 2002 for additional information on "round-trip" trading). On April
30, 2003, the FERC issued an order consistent with the FERC staff's March 26,
2003 recommendations directing Duke Energy and ten other companies to submit by
June 16, 2003 written demonstrations regarding gas price reporting practices.
Duke Energy continues to evaluate the staff recommendations and refund order to
analyze the impact they might have on Duke Energy.
Related Litigation. In December 2002, plaintiffs filed class-action suits
against Duke Energy and numerous other energy companies in state court in Oregon
and in federal court in Washington state making allegations similar to those in
the California suits. Plaintiffs allege they paid unreasonably high prices for
electricity and/or natural gas during the time period from January 2000 to the
present as a result of defendants' activities which were fraudulent, negligent
and in violation of each state's business practices laws. Plaintiffs have sought
to dismiss these two suits, and in April 2003 a new class action lawsuit was
filed against Duke Energy and numerous other energy companies in state court in
San Diego, California on behalf of purchasers of electric and/or natural gas
energy residing in the states of Oregon, Washington, Utah, Nevada, Idaho, New
Mexico, Arizona, and Montana. Plaintiffs claim that wholesale and retail pricing
throughout the "West Coast Energy Market" is dominated by trading and pricing in
California and allege that defendants, acting unilaterally and in concert with
other energy companies, engaged in manipulation of the supply of energy into the
California markets, resulting in artificially high electricity prices.
Plaintiffs, also alleging that defendants' actions were in violation of
California's antitrust and unfair business practices laws, seek actual and
treble damages; restitution of funds acquired by unfair or unlawful means; an
injunction prohibiting the defendants from engaging in the alleged unlawful
activity; and other appropriate relief.
In March 2003 a California state court in Los Angeles unsealed a lawsuit
originally filed August 2002 against numerous energy company defendants,
including DETM. The plaintiffs, seeking to act on behalf of the State of
California under the False Claims Act, made claims similar to those in other
lawsuits alleging manipulation of the electricity market in California, and
claim that defendants, conspiring to defraud state governmental entities, made
"false records or statements." The plaintiffs sought unspecified damages in the
maximum amount allowed under the pertinent laws. On January 15, 2003, this
lawsuit was dismissed without prejudice.
Trading Matters. In October 2002, the FERC issued a data request to the "Largest
North American Gas Marketers, As Measured by 2001 Physical Sales Volumes
(Bcf/d)," including DETM. In general, the data request asks for information
concerning natural gas price data submitted by the gas marketers to publishers
of natural gas price indices. DETM responded to the FERC's data request, and is
also responding to requests by the Commodities Future Trading Commission (CFTC)
for similar information. The March 26, 2003 FERC staff recommendations (see
"Western Power Disputes" above) included a report on the FERC's investigation
regarding information provided to publications. The report noted that the
practice in Duke Energy's Salt Lake City office was to report actual
transactions while the practice in the Houston office was to report a sense of
the market while sometimes taking Duke Energy's open positions into account. The
FERC staff report also identified controls that should be implemented to address
inaccurate reporting of information to trade publications. Duke Energy has
implemented the controls identified in the report. Management is unable to
predict what, if any, action the FERC and the CFTC will take with respect to
these matters.
Sonatrach/ Citrus Trading Corporation (Citrus). In a matter related to the
Sonatrach arbitration (see Note 16 to the Consolidated Financial Statements,
"Commitments and Contingencies - Litigation, Sonatrach," in Duke Energy's Form
10-K for December 31, 2002), Citrus filed suit in March 2003 against Duke Energy
LNG Sales, Inc. (Duke LNG) in the District Court of Harris County, Texas. The
suit alleged that Duke LNG breached the parties' natural gas purchase contract
(the Citrus Agreement) by failing to provide sufficient volumes of gas to
Citrus. Duke LNG contends that as a result of Sonatrach's actions, Duke LNG
experienced a loss of liquefied natural gas (LNG) supply that affects Duke LNG's
obligations and
21
termination rights under the Citrus Agreement. The Citrus petition seeks
unspecified damages and a judicial determination that contrary to Duke LNG's
position, Duke LNG has not experienced a loss of LNG supply. Duke LNG
subsequently terminated the Citrus contract and filed a counterclaim in the
Texas action asserting that Citrus breached the terms of the Citrus Agreement
by, among other things, failing to provide sufficient security for the gas
transactions. Citrus has denied that Duke LNG has the right to terminate the
agreement. Duke Energy continues to evaluate the claims at issue in this matter
and intends to vigorously defend itself.
Enron Bankruptcy. In December 2001, Enron filed for relief pursuant to Chapter
11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the
Southern District of New York. Additional affiliates have filed for bankruptcy
since that date. Certain affiliates of Duke Energy engaged in transactions with
various Enron entities prior to the bankruptcy filings. DETM was a member of the
Official Committee of Unsecured Creditors in the bankruptcy cases which are
being jointly administered, but as of February 2003, DETM resigned from the
Official Committee of Unsecured Creditors in the Enron bankruptcy case. In 2001,
Duke Energy recorded a reserve to offset its exposure to Enron.
In mid-November 2002, various Enron trading entities demanded payment from DETM
and DEM for certain energy commodity sales transactions without regard to the
set-off rights of DETM and DEM, and demanded that DETM detail balances due under
certain master trading agreements without regard to the set-off rights of DETM.
On December 13, 2002, DETM and DEM filed an adversary proceeding against Enron,
seeking, among other things, a declaration affirming each plaintiff's right to
set off its respective debts to Enron. The complaint alleges that the Enron
affiliates were operated by Enron as its alter-ego and as components of a single
trading enterprise, and that DETM and DEM should be permitted to exercise their
respective rights of mutual set-off against the Enron trading enterprise under
the Bankruptcy Code. The complaint also seeks the imposition of a constructive
trust, so that any claims by Enron against DETM or DEM are subject to the
respective set-off rights of DETM and DEM. On April 17, 2003, DETM and DEM's
adversary proceeding was dismissed by the bankruptcy judge for lack of standing.
On April 30, 2003, DETM and DEM filed their notice of appeal of this decision.
Management believes that the final disposition of the Enron bankruptcy will have
no material adverse effect on consolidated results of operations, cash flows or
financial position.
Other Litigation and Legal Proceedings. Duke Energy and its subsidiaries are
involved in other legal, tax and regulatory proceedings before various courts,
regulatory commissions and governmental agencies regarding performance,
contracts, royalty disputes, mismeasurement and mispayment claims (some of which
are brought as class actions), and other matters arising in the ordinary course
of business, some of which involve substantial amounts. Management believes that
the final disposition of these proceedings will have no material adverse effect
on consolidated results of operations, cash flows or financial position.
9. Guarantees and Indemnifications
Duke Energy and certain of its subsidiaries have various financial and
performance guarantees and indemnifications which are issued in the normal
course of business. As discussed below, these contracts include performance
guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. Duke Energy enters into these arrangements to facilitate a
commercial transaction with a third party by enhancing the value of the
transaction to the third party.
Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the
prime contractor to the U.S. Department of Energy (DOE) under a contract (the
Prime Contract) in which DCS will design, construct, operate and deactivate a
MOX fuel fabrication facility (MOX FFF). The domestic MOX fuel project was
prompted by an agreement between the U.S. and the Russian Federation to dispose
of their respective excess weapon-grade plutonium by fabricating MOX fuel and
irradiating such MOX fuel in commercial nuclear reactors. As of March 31, 2003,
Duke Energy, through its indirect wholly owned subsidiary, Duke Project Services
Group, Inc. (DPSG), held a 40% ownership interest in DCS.
22
Additionally, Duke Power has entered into a subcontract with DCS (the Duke Power
Subcontract) to prepare its McGuire and Catawba nuclear reactors (the Nuclear
Reactors) for use of the MOX fuel and to purchase MOX fuel produced at the MOX
FFF for use in the Nuclear Reactors.
As required under the Prime Contract, DPSG and the other owners of DCS have
issued a guarantee to the DOE (the DOE Guarantee) pursuant to which the owners
of DCS jointly and severally guarantee to the DOE all of DCS' payment and
performance obligations under the Prime Contract. The Prime Contract consists of
a "Base Contract" phase and three optional phases. The DOE has the right to
extend the term of the Prime Contract to cover the three optional phases on a
sequential basis, subject to DCS and DOE reaching agreement, through good-faith
negotiations on certain remaining open terms applying to each of the option
phases. Each of the three option phases will be negotiated separately, as the
time for exercising each option phase becomes due under the Prime Contract. If
the DOE does not exercise its right to extend the term of the Prime Contract to
cover any or all of the optional phases, DCS' performance obligations under the
Prime Contract will end upon completion of the then-current performance phase.
Under the Base Contract phase, which covers the design of the MOX FFF and design
modifications to the Nuclear Reactors, DCS is to receive cost reimbursement plus
a fixed fee. The first option phase includes construction and cold startup of
the MOX FFF and modification of the Nuclear Reactors, and provides for DCS to
receive cost reimbursement plus an incentive fee. The second option phase
provides for taking the MOX FFF from cold to hot startup, operation of the MOX
FFF, and irradiation of the MOX fuel in the Nuclear Reactors. For the second
option phase, DCS is to receive a cost reimbursement plus an incentive fee
through hot startup and, thereafter, cost-sharing plus a fee. The third option
phase involves DCS' deactivation of the MOX FFF in exchange for a fixed price
payment. As of March 31, 2003, DCS' performance obligations under the Prime
Contract include only the Base Contract phase, since the DOE has not yet
exercised its option to extend the term of performance under the Prime Contract
to the first option phase, and DCS and the DOE have not yet agreed on all open
terms and conditions applicable to that phase.
Additionally, DPSG and the other owners of DCS have issued a guarantee to Duke
Power(the Duke Power Guarantee) under which the owners of DCS jointly and
severally guarantee to Duke Power all of DCS' payment and performance
obligations under the Duke Power Subcontract or any other agreement between DCS
and Duke Power implementing the Prime Contract. The Duke Power Subcontract
consists of a "Base Subcontract" phase and two optional phases. DCS has the
right to extend the term of the Duke Power Subcontract to cover the two option
phases on a sequential basis, subject to Duke Power and DCS reaching agreement,
through good-faith negotiations on certain remaining open terms applying to each
of the option phases. Under the Base Subcontract phase, Duke Power will perform
technical and regulatory work required to prepare the Nuclear Reactors to use
MOX fuel, and receive cost reimbursement plus a fixed fee. The first option
phase provides for modification to the Nuclear Reactors as well as additional
technical and regulatory work, and provides for Duke Power to receive cost
reimbursement plus a fee. The second option phase provides for Duke Power to
purchase from DCS MOX fuel produced at the MOX FFF for use in the Nuclear
Reactors, at discounts to prices of equivalent uranium fuel, over a 15-year
period starting upon completion of the first option phase. As of March 31, 2003,
DCS' performance obligations under the Duke Power Subcontract include only the
Base Subcontract phase, since DCS has not yet exercised its option to extend the
term of performance under the Duke Power Subcontract to the first option phase,
and DCS and Duke Power have not yet agreed on all open terms and conditions
applicable to that phase.
The cost reimbursement nature of DCS' commitment under the Prime Contract and
the Duke Power Subcontract limits the exposure of DCS. Credit risk to DCS is
limited in that the Prime Contract is with the DOE, a U.S. governmental entity.
DCS is under no obligation to perform any contract work under the Prime Contract
before funds have been appropriated from the U.S. Congress.
Duke Energy is unable to estimate the maximum potential amount of future
payments DPSG could be required to make under the DOE Guarantee and the Duke
Power Guarantee due to the uncertainty of whether: the DOE will exercise its
options under the Prime Contract; the parties to the Prime Contract and the Duke
Power Subcontract, respectively, will reach agreement on the remaining open
terms for each option phase under the contracts; and the U.S. Congress will
authorize funding for DCS' work under the Prime Contract. Any liability of DPSG
under the DOE Guarantee or the Duke Power Guarantee is directly
23
related to and limited by the Prime Contract and the Duke Power Subcontract,
respectively. DPSG also has recourse to the other owners of DCS for any amounts
paid under the DOE Guarantee or the Duke Power Guarantee in excess of its
proportional ownership percentage of DCS.
As of March 31, 2003, Duke Energy had no material liabilities recorded on its
Consolidatd Balance Sheet for the above mentioned MOX guarantees.
Other Guarantees and Indemnifications. Duke Capital Corporation has issued
performance guarantees to customers and other third parties that guarantee the
payment and performance of other parties, including certain non-wholly owned
entities. The maximum potential amount of future payments Duke Capital
Corporation could have been required to make under these performance guarantees
as of March 31, 2003 was approximately $650 million. Of this amount,
approximately $275 million relates to guarantees of the payment and performance
of less than wholly owned consolidated entities. Approximately $150 million of
the performance guarantees expire in 2003 and approximately $25 million expire
in 2004, with the remaining performance guarantees having no contractual
expiration. Additionally, Duke Capital Corporation has issued joint and several
guarantees to certain of the D/FD project owners, which guarantee the
performance of D/FD under its engineering, procurement and construction
contracts and other contractual commitments. These guarantees have no
contractual expiration and no stated maximum amount of future payments that Duke
Capital Corporation could be required to make. Additionally, Fluor Enterprises,
Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to
the same D/FD project owners. In accordance with the D/FD partnership agreement,
each of the D/FD partners is responsible for 50% of any payments to be made
under these guarantee contracts.
Westcoast has issued performance guarantees to third parties guaranteeing the
performance of unconsolidated entities, such as equity method projects, and of
entities previously sold by Westcoast to third parties. These performance
guarantees require Westcoast to make payment to the guaranteed third party upon
the failure of the unconsolidated entity to make payment under certain of its
contractual obligations, such as debt, purchase contracts and leases. The
maximum potential amount of future payments Westcoast could have been required
to make under these performance guarantees as of March 31, 2003 was
approximately $150 million. Of these guarantees, approximately $25 million
expire from 2004 to 2007, with the remainder expiring after 2007 or having no
contractual expiration.
Stand-by letters of credit are conditional commitments issued by banks to
guarantee the performance of non-wholly owned entities to a third party or
customer. Under these agreements, Duke Capital Corporation and Westcoast have
payment obligations which are triggered by the failure of a non-wholly owned
entity to make payment to a third party or customer, according to the terms of
the underlying contract and the subsequent draw by the third party or customer
under the letter of credit. These letters of credit expire in various amounts
between 2003 and 2004. The maximum potential amount of future payments Duke
Capital Corporation and Westcoast could have been required to make under these
letters of credit as of March 31, 2003 was approximately $350 million. Of this
amount, approximately $275 million relates to letters of credit issued on behalf
of less than wholly owned consolidated entities. Related to these letters of
credit, Duke Capital Corporation has received collateral from non-wholly owned
consolidated entities in the amount of approximately $125 million as of March
31, 2003.
Duke Capital Corporation has guaranteed the issuance of surety bonds, obligating
itself to make payment upon the failure of a non-wholly owned entity to honor
its obligations to a third party. As of March 31, 2003, Duke Capital Corporation
had guaranteed approximately $100 million of outstanding surety bonds related to
obligations of non-wholly owned entities. These bonds expire in various amounts,
primarily between 2003 and 2004. Of this amount, approximately $10 million
relates to obligations of less than wholly owned consolidated entities.
Field Services and Natural Gas Transmission have issued certain guarantees of
debt associated with non-consolidated entities. In the event that the
non-consolidated entity defaults on the debt payments, Field Services and
Natural Gas Transmission would be required to perform under the guarantees and
make payment on the outstanding debt balance of the non-consolidated entity. As
of March 31, 2003, Field
24
Services was the guarantor of approximately $100 million of debt associated with
non-consolidated entities. Natural Gas Transmission was the guarantor of
approximately $10 million of debt associated with non-consolidated entities
(including $5 million related to Westcoast). These guarantees principally expire
in 2003 for Field Services and 2019 for Natural Gas Transmission.
Duke Energy has certain guarantees issued to customers or other third parties
related to the payment or performance obligations of certain entities that were
previously wholly owned but which have been sold to third parties, such as
DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc.
(DE&S). These guarantees are primarily related to payment of lease obligations,
debt obligations and performance guarantees related to goods and services
provided. In connection with the sale of DE&S, Duke Energy has received
back-to-back indemnification from the buyer indemnifying Duke Energy for any
amounts paid by Duke Energy related to the DE&S guarantees. In connection with
the sale of DukeSolutions, Duke Energy received indemnification from the buyer
for the first $2.5 million paid by Duke Energy related to the DukeSolutions
guarantees. Additionally, for certain performance guarantees, Duke Energy has
recourse to subcontractors involved in providing services to a customer. These
guarantees have various terms ranging from 2003 to 2019, with others having no
specific term. Duke Energy is unable to estimate the total maximum potential
amount of future payments under these guarantees since most of the underlying
guaranteed agreements contain no limits on potential liability.
Duke Energy has entered into various indemnification agreements related to
purchase and sale agreements and other types of contractual agreements with
vendors and other third parties. These indemnification agreements typically
cover environmental, tax, litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these agreements.
Typically, claims may be made by third parties under these indemnification
agreements for various periods of time depending on the nature of the claim.
Duke Energy's maximum potential exposure under these indemnification agreements
can range from a specified dollar amount to an unlimited amount depending on the
nature of the claim and the particular transaction. Duke Energy is unable to
estimate the total maximum potential amount of future payments under these
indemnification agreements due to several factors, including uncertainty as to
whether claims will be made under these indemnities.
As of March 31, 2003, Duke Energy had recorded no material liabilities for the
guarantees and indemnifications mentioned above.
10. Subsequent Events
In April 2003, Duke Energy closed on substantially all elements of a transaction
to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada
Marketing and Aux Sable natural gas liquids plant to Enbridge Inc. and Fort
Chicago Energy Partners L.P. for approximately $250 million. This sale resulted
in an immaterial net loss. The transaction was completed except for Duke
Energy's small ownership interest related to the U.S. segment of Alliance
Pipeline, which is expected to close in October 2003 and represents
approximately $11 million in proceeds. Alliance Pipeline extends from Fort St.
John in British Columbia to Chicago, Illinois. The Aux Sable plant extracts
natural gas liquids at the outlet of the Alliance Pipeline in Chicago. Duke
Energy obtained its minority ownership interest in the Alliance natural gas
pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant
through its acquisition of Westcoast in 2002.
In April 2003, Duke Energy sold all its Class B units of TEPPCO Partners, L.P.
(TEPPCO) for approximately $114 million. Duke Energy recorded a pre-tax gain of
approximately $11 million on the sale. TEPPCO is a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil.
In April and May 2003, DEFS entered into two separate purchase and sale
agreements by which it will sell one package of assets to Crosstex Energy
Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy,
LLC (ScissorTail) for a total sales price of approximately $91 million, plus or
minus various adjustments to be made at closing. The gain on the sale will be
approximately $17 million (at Duke
25
Energy's approximately 70% share). The assets to be sold to Crosstex consist of
the AIM Pipeline System in Mississippi; a 12.4% interest in the Seminole gas
processing plant in Texas; the Conroe gas plant and gathering system in Texas;
the Black Warrior pipeline system in Alabama; and two smaller systems - Aurora
Centana and Cadeville in Louisiana. The assets to be sold to ScissorTail consist
of various gas processing plants and gathering pipeline in eastern Oklahoma. The
transactions are expected to close by June 30, 2003. The sale to Crosstex is
subject to regulatory approvals.
For information on subsequent events related to regulatory matters see Note 5,
Notices of Proposed Rulemaking section. For information on subsequent events
related to litigation and contingencies see Note 8, Litigation section. For
information on subsequent events related to debt and other financing matters see
Note 7.
26
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
INTRODUCTION
Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), an
integrated provider of energy and energy services, offers physical delivery and
management of both electricity and natural gas throughout the U.S. and abroad.
Duke Energy provides these and other services through its business segments. See
Note 1 to the Consolidated Financial Statements for descriptions of Duke
Energy's business segments.
Management's Discussion and Analysis should be read in conjunction with the
Consolidated Financial Statements.
RESULTS OF OPERATIONS
For the three months ended March 31, 2003, earnings available for common
stockholders were $222 million, or $0.25 per basic share. For the comparable
2002 period, earnings available for common stockholders were $379 million, or
$0.48 per basic share. The decrease was due primarily to charges related to
changes in accounting principles of $162 million, or $0.18 per basic share.
Those changes included an after-tax charge of $151 million, or $0.17 per basic
share, related to the implementation of the Emerging Issues Task Force (EITF)
Issue No. 02-03, "Issued Involved in Accounting for Derivative Contracts Held
for Trading Purposes and for Contracts Involved in Energy Trading and Risk
Management Activities" and a charge of $11 million, or $0.01 per basic share,
due to the implementation of Statement of Financial Accounting Standards (SFAS)
No. 143, "Accounting for Asset Retirement Obligations."
Total consolidated operating revenues for the three months ended March 31, 2003
increased $3,016 million to $6,324 million from $3,308 million for the three
months ended March 31, 2002. The increase resulted primarily from significantly
higher natural gas liquid (NGL) pricing; two additional months of
transportation, storage and distribution revenues from assets acquired or
consolidated as part of the Westcoast Energy Inc. (Westcoast) acquisition in
March 2002; and the adoption of the final consensus on EITF Issue No. 02-03 upon
which Duke Energy began to recognize revenues for certain natural gas and other
contracts on a gross basis. Adopting the final consensus on EITF Issue No. 02-03
did not require a change to prior periods, and therefore Duke Energy did not
change 2002 operating revenue and operating expense amounts.
Total consolidated operating expenses for the three months ended March 31, 2003
increased $2,791 million to $5,431 million from $2,640 million for the three
months ended March 31, 2002. The increase resulted primarily from significantly
higher NGL pricing; two additional months of operating expenses from assets
acquired or consolidated as part of the Westcoast acquisition in March 2002; and
the adoption of the final consensus on EITF Issue No. 02-03, after which Duke
Energy began to present revenues and expenses for certain natural gas
transactions on a gross basis in 2003. Adopting the final consensus on EITF
Issue No. 02-03 did not require a change to prior periods and therefore Duke
Energy did not change the 2002 operating revenue and operating expense amounts.
Operating income was $893 million and earnings before interest and taxes (EBIT)
were $974 million for the three months ended March 31, 2003. This compares to
operating income of $668 million and EBIT of $770 million for the same period in
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 consolidated operating income and EBIT to net
income.
27
==============================================================================
Reconciliation of Operating Income and EBIT to Net Income (in millions)
- ------------------------------------------------------------------------------
Three Months Ended
March 31,
--------------------------------
2003 2002
--------------------------------
Operating income $893 $668
Other income and expenses 81 102
--------------------------------
EBIT 974 770
Interest expense 340 198
Minority interest expense 52 32
--------------------------------
Earnings before income taxes 582 540
Income taxes 195 158
--------------------------------
Income before cumulative
effect of changes in accounting
principles 387 382
Cumulative effect of changes in accounting
principles, net of tax (162) -
--------------------------------
Net income $225 $382
==============================================================================
EBIT for the three months ended March 31, 2003 increased $204 million to $974
million from $770 million for the three months ended March 31, 2002. The
increase resulted primarily from two additional months of transportation,
storage and distribution income from assets acquired or consolidated as part of
the Westcoast acquisition, and increased operating income at Duke Energy's
Franchised Electric segment, driven by increased wholesale power sales and
favorable weather.
For a more detailed discussion of EBIT, see segment discussions below.
EBIT may be viewed as a non-Generally Accepted Accounting Principles (GAAP)
measure under the rules of the Securities and Exchange Commission (SEC). Duke
Energy has included EBIT in its disclosures because it is the primary
performance measure used by management to evaluate total company and segment
performance. On a segment basis, it includes all profits (both operating and
non-operating) before deducting interest and taxes, and is net of the minority
interest expense related to those profits. Management believes EBIT is a good
indicator of each segment's operating performance, as it represents the results
of Duke Energy's ownership interests in operations without regard to financing
methods or capital structure. As an indicator of Duke Energy's operating
performance, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with GAAP. Duke
Energy's EBIT may not be comparable to a similarly titled measure of another
company because other entities may not calculate EBIT in the same manner.
28
Business segment EBIT is summarized in the following table, and detailed
discussions follow.
=============================================================================================
EBIT by Business Segment (in millions)
- ---------------------------------------------------------------------------------------------
Three Months Ended
March 31,
-----------------------------
2003 2002
-----------------------------
Franchised Electric $454 $ 384
Natural Gas Transmission 423 266
Field Services 33 35
Duke Energy North America 23 54
International Energy 54 57
Other Operations (26) 17
Other/a/ (31) (107)
-----------------------------
Total Segment EBIT 930 706
EBIT attributable to:
Minority Interests 46 14
Third Party Interest Income 3 41
Foreign Currency (Loss) Gain (5) 9
-----------------------------
Consolidated EBIT $974 $ 770
=============================================================================================
/a/ Other primarily includes certain unallocated corporate costs and
elimination of intersegment profits.
The amounts discussed below include intercompany transactions that are
eliminated in the Consolidated Financial Statements.
Franchised Electric
=============================================================================================
Three Months Ended
March 31,
-----------------------------
(in millions, except where noted) 2003 2002
- ---------------------------------------------------------------------------------------------
Operating revenues $ 1,251 $ 1,113
Operating expenses 813 746
-----------------------------
Operating income 438 367
Other income, net of expenses 16 17
-----------------------------
EBIT $ 454 $ 384
=============================
Sales, GWh/a/ 22,043 19,521
=============================================================================================
/a/ Gigawatt-hours
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $138 million to $1,251 million from $1,113 million for the three
months ended March 31, 2002. The increase resulted primarily from increased
wholesale power sales, which contributed $111 million as a result of favorable
weather and market conditions coupled with outstanding availability and
performance of the generating fleet. Also contributing to the revenue growth
were increased GWh sales to retail customers, driven by favorable weather, which
contributed $35 million.
The following table shows the changes in GWh sales and average number of
customers.
==================================================================
Increase (decrease) over prior year Three Months Ended
- ------------------------------------------------------------------
Residential sales 9.1%
General service sales 4.1%
Industrial sales (0.9)%
Total Franchised Electric sales 12.9%
Average number of customers 2.2%
==================================================================
29
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $67 million to $813 million from $746 million for the three months
ended March 31, 2002. As a result of the increase in electric sales, fuel costs
increased by $42 million. Additionally, severe winter storms in 2003 resulted in
$35 million in expenses and amortization expense increased by $17 million
related to North Carolina's 2002 clean air legislation. These costs were
partially offset by lower outage costs of $16 million at Duke Power's generating
plants.
EBIT. EBIT for the three months ended March 31, 2003 increased $70 million to
$454 million from $384 million for the three months ended March 31, 2002, due
primarily to increased wholesale power sales, favorable weather and market
conditions. The increase was partially offset by increased operating expenses
which were driven by fuel costs, storm charges and amortization expense.
Natural Gas Transmission
=============================================================================================
Three Months Ended
March 31,
-----------------------------
(in millions, except where noted) 2003 2002
- ---------------------------------------------------------------------------------------------
Operating revenues $ 968 $450
Operating expenses 567 218
-----------------------------
Operating income 401 232
Other income, net of expenses 35 37
Minority interest expense 13 3
-----------------------------
EBIT $ 423 $266
=============================
Proportional throughput, TBtu/a/ 1,082 670
=============================================================================================
/a/ Trillion British thermal units
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $518 million to $968 million from $450 million for the three months
ended March 31, 2002. This increase resulted primarily from January and February
2003 transportation, storage and distribution revenue of $466 million from
assets acquired or consolidated as a part of the Westcoast acquisition in March
2002. Revenues also increased $10 million due to business expansion projects.
Operating revenues for the month of March 2003 versus the month of March 2002
also increased approximately $30 million due to increased natural gas prices and
volumes at Union Gas Limited (Union Gas), the natural gas distribution
operations in Ontario.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $349 million to $567 million from $218 million for the three months
ended March 31, 2002. This increase was due primarily to incremental operating
expenses of $319 million related to January and February 2003 operations of the
gas transmission, storage and distribution assets acquired or consolidated in
the Westcoast acquisition in March 2002. Operating expenses for the month of
March 2003 versus the month of March 2002 also increased approximately $30
million due to increased natural gas prices and volumes at Union Gas.
Minority Interest Expense. Minority interest expense for the three months ended
March 31, 2003 increased $10 million to $13 million from $3 million for the
three months ended March 31, 2002. This increase resulted from recognizing a
full quarter of minority interest expense in 2003, versus only one month during
the first quarter of 2002, from less than wholly owned subsidiaries acquired in
the March 2002 acquisition of Westcoast.
EBIT. EBIT for the three months ended March 31, 2003 increased $157 million to
$423 million from $266 million for the three months ended March 31, 2002. As
discussed above, this increase resulted primarily from incremental EBIT related
to assets acquired or consolidated as part of the March 2002 acquisition of
30
Westcoast, which contributed $135 million of incremental EBIT to first quarter
2003. First quarter 2003 and 2002 results both include gains of $14 million from
the sales of Natural Gas Transmission's limited partnership interests in
Northern Borders Partners L.P.
Field Services
=============================================================================================
Three Months Ended
March 31,
-----------------------------
(in millions, except where noted) 2003 2002
- ---------------------------------------------------------------------------------------------
Operating revenues $2,472 $1,134
Operating expenses 2,426 1,099
-----------------------------
Operating income 46 35
Other income, net of expenses 15 8
Minority interest expense 28 8
-----------------------------
EBIT $ 33 $ 35
=============================
Natural gas gathered and processed/transported, TBtu/d /a/ 8.0 8.4
NGL production, MBbl/d /b/ 375.2 388.6
Average natural gas price per MMBtu /c/ $ 6.59 $ 2.32
Average NGL price per gallon /d/ $ 0.58 $ 0.31
=============================================================================================
/a/ Trillion British thermal units per day
/b/ Thousand barrels per day
/c/ Million British thermal units
/d/ Does not reflect results of commodity hedges
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $1,338 million to $2,472 million from $1,134 million for the same
period in 2002. The increase was primarily driven by increases of approximately
$1,406 million on the sale of natural gas, NGLs and other petroleum products.
These increases were mainly driven by a $0.27 per gallon increase in average NGL
prices, and a $4.27 per MMBtu increase in natural gas prices. Partially
offsetting the NGL and natural gas price increases were reduced levels of
natural gas gathered and processed/transported (throughput) of 0.4 TBtu per day.
Also contributing to higher revenues were increased transportation, storage and
processing fees, offset by a decrease in net trading margin and losses resulting
from hedging activity.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $1,327 million to $2,426 million from $1,099 million for the same
period in 2002. The increase was due primarily to increases of approximately
$1,314 million in expenses related to purchases of natural gas, NGLs and other
petroleum products. These increases were mainly driven by a $0.27 per gallon
increase in average NGL prices, and a $4.27 per MMBtu increase in natural gas
prices. Partially offsetting the NGL and natural gas price increases were
reduced levels of natural gas gathered and processed/transported (throughput) of
0.4 TBtu per day. Also contributing to the increase in expenses were slightly
higher operating and maintenance, and depreciation costs.
Minority Interest Expense. Minority interest expense for the three months ended
March 31, 2003 increased $20 million to $28 million from $8 million for the
three months ended March 31, 2002. This increase was due primarily to increased
earnings from Duke Energy Field Services, LLC (DEFS), Duke Energy's joint
venture with ConocoPhillips.
EBIT. The decrease in EBIT of $2 million was largely the result of higher NGL
prices being substantially offset by higher natural gas prices, hedging activity
and increases in minority interest expense.
31
Duke Energy North America (DENA)
========================================================================================
Three Months Ended
March 31,
------------------------
(in millions, except where noted) 2003 2002
- ----------------------------------------------------------------------------------------
Operating revenues $ 1,396 $ 258
Operating expenses 1,382 200
------------------------
Operating income 14 58
Other income (loss), net of expenses 9 (4)
------------------------
EBIT $ 23 $ 54
========================
Actual plant production, GWh 5,110 3,868
Proportional megawatt capacity in operation 14,156 7,515
========================================================================================
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $1,138 million to $1,396 million from $258 million for the same period
in 2002. Increases in net generation assets in operation and in the average
price realized for electricity generated, resulted in a $120 million increase in
operating revenue. In addition, revenues increased $1,019 million in connection
with the implementation of the remaining provisions of EITF Issue N0. 02-03. As
a result of adopting EITF Issue N0. 02-03 on January 1, 2003, gains and losses
for certain derivative and non-derivative contracts that were previously
reported on a net basis in Trading and Marketing Net Margin under EITF Issue N0.
98-10 are now reported on a gross basis. Specifically, the $1,019 million
increase is primarily related to the presentation effective on January 1, 2003,
of certain derivative contracts related to DENA's wholesale natural gas
marketing operations and the presentation of gains and losses from the
settlement of many non-derivative contracts on a gross basis in the Consolidated
Statements of Income. These increases were partially offset by decrease net
margins due to lower proprietary trading results.
Duke Energy adopted EITF Issue No. 02-03 and did not change the 2002 operating
revenue and operating expense amounts.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $1,182 million to $1,382 million from $200 million for the same period
in 2002. Changes in volumes and prices surrounding merchant generation plants
contributed $113 million to this increase. Similar to the increase in operating
revenues discussed above, operating expenses also increased $987 million due to
the adoption of the final consensus on EITF Issue No. 02-03. Also contributing
to the increase in operating expenses was increased depreciation expense of $28
million, related primarily to eight new plants going into commercial operation
and/or acquired in the second quarter of 2002. Additionally, these increases in
operating expenses were partially offset by lower general and administrative
expenses in 2003 as a result of DENA's realignment of its operations at the end
of 2002.
EBIT. EBIT for the three months ended March 31, 2003, decreased $31 million to
$23 million from $54 million for the same period in 2002. The decline was
primarily driven by lower proprietary trading results and increased operating
expenses as discussed above. These EBIT decreases were partially offset by
increases in other income, net of expenses of $13 million. The increase in other
income, net of expenses was due primarily to higher equity earnings from
American Ref-Fuel Company, LLC which owns and operates facilities that convert
waste to energy.
In March 2003, DENA entered into an agreement to sell its 50% ownership interest
in Duke/UAE Ref-Fuel LLC for $306 million to Highstar Renewable Fuels LLC.
Duke/UAE Ref-Fuel LLC owns American Ref-Fuel Company LLC, a holding company for
six waste-to-energy facilities in the northeastern U.S. The transaction, which
is subject to a number of conditions including certain regulatory approvals, is
expected to be finalized later in 2003 and DENA expects to record a gain upon
completion of this transaction.
32
International Energy
=============================================================================================
Three Months Ended
March 31,
------------------------
(in millions, except where noted) 2003 2002
- ---------------------------------------------------------------------------------------------
Operating revenues $ 382 $ 289
Operating expenses 331 235
------------------------
Operating income 51 54
Other income, net of expenses 8 8
Minority interest expense 5 5
------------------------
EBIT $ 54 $ 57
========================
Sales, GWh 4,759 4,932
Proportional megawatt capacity in operation 4,887 4,705
Proportional maximum pipeline capacity in operation, MMcf/d /a/ 363 363
=============================================================================================
/a/ Million cubic feet per day
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $93 million to $382 million from $289 million for the same period in
2002. Of this increase $148 million was due to the adoption of the final
consensus on EITF Issue No. 02-03. As a result of implementing EITF Issue No.
02-03, International Energy began to recognize certain natural gas transactions
on a gross basis in 2003. Duke Energy adopted EITF Issue No. 02-03 and did not
change 2002 operating revenue and operating expense amounts. Also contributing
to the increase were $20 million in revenues from assets acquired in France
during 2002, $13 million from increased energy prices and GWhs sold at
International Energy's Latin American operating facilities, and $18 million from
increased gas prices related to liquified natural gas operations. These
increases were partially offset by a one-time increase in 2002 revenues for the
final guidance in Brazil on free energy exposure related to rationing of $91
million, and the negative impacts of currency devaluations within Brazil and
Argentina of $21 million.
Operating Expenses. Operating expenses for the three months ended March 31,
2003, increased $96 million to $331 million from $235 million for the same
period in 2002. Similar to the increase in operating revenues described above,
operating expenses increased $148 million due to the adoption of the final
consensus on EITF Issue No. 02-03. Additionally, increased fuel expenses from
assets acquired in France contributed expenses of $9 million; increased prices
and generation within International Energy's Latin America operating facilities
added $14 million of expenses; and increased prices on gas purchased to cover
liquefied natural gas contracts increased expenses by $17 million. Increased
operating expenses were partially offset by a one-time increase in 2002 expenses
for the final guidance in Brazil on free energy exposures related to rationing
of $91 million and favorable impacts of $13 million due to currency devaluations
within Brazil and Argentina.
EBIT. For the three months ended March 31, 2003, International Energy reported
EBIT of $54 million compared, to EBIT of $57 million for the same period in
2002. Included in International Energy's first quarter 2003 EBIT is a
non-recurring, non-cash charge of $11 million related to the timing of revenue
recognition at the Cantarell investment in Mexico, a nitrogen-production plant
which was acquired with Westcoast.
33
Other Operations
=============================================================================================
Three Months Ended
March 31,
-----------------------------
(in millions) 2003 2002
- ---------------------------------------------------------------------------------------------
Operating revenues $556 $188
Operating expenses 589 184
-----------------------------
Operating (loss) income (33) 4
Other income, net of expenses 7 13
-----------------------------
EBIT $(26) $ 17
=============================================================================================
Operating Revenues. Operating revenues for the three months ended March 31, 2003
increased $368 million to $556 million from $188 million for the same period in
2002. The increase was due primarily to the adoption of the final consensus on
EITF Issue No. 02-03 by Duke Energy Merchants Holdings, LLC (DEM). As a result
of adopting EITF Issue No. 02-03 on January 1, 2003, gains and losses for
certain derivative and non-derivative contracts that were previously reported on
a net basis in Trading and Marketing Net Margin under EITF Issue No. 98-10 are
now reported on a gross basis. Duke Energy adopted EITF Issue No. 02-03 and did
not change 2002 operating revenue or operating expense amounts. This increase
was partially offset by the sale of Duke Engineering & Services, Inc. (DE&S) and
DukeSolutions, Inc. (DukeSolutions) in 2002, which contributed $125 million to
revenues during the first quarter of 2002. The increase in revenues was also
offset by decreases in DEM's trading and marketing net margin and the
substantial completion of DEM's exit from proprietary trading during the three
months ended March 31, 2003.
Operating Expenses. Operating expenses for the three months ended March 31, 2003
increased $405 million to $589 million from $184 million for the same period in
2002. Similar to the increase in operating revenues described above, the
increase in operating expenses was due primarily to the adoption of the final
consensus on EITF Issue No. 02-03 and charges at DEM related to exiting the
proprietary trading and hydrocarbons business. These increases were partially
offset by the sale of DE&S and DukeSolutions in 2002, which contributed $122
million to operating expenses during the first quarter of 2002.
EBIT. EBIT for the three months ended March 31, 2003 decreased $43 million to a
loss of $26 million from income of $17 million for the same period in 2002. The
decline in EBIT was primarily driven by charges at DEM related to exiting the
proprietary trading and hydrocarbons businesses.
Other Impacts on Earnings Available for Common Stockholders
For the three months ended March 31, 2003, interest expense increased $142
million compared to the same period in 2002. The increase was due primarily to
higher debt balances resulting from debt assumed in, and issued with respect to,
the acquisition of Westcoast; lower capitalized interest for DENA; and
additional debt.
Minority interest expense increased $20 million for the three months ended March
31, 2003, as compared to the same period in 2002. Minority interest expense
includes expense related to regular distributions on preferred securities of
Duke Energy and its subsidiaries, which decreased for the three months ended
March 31, 2003, as compared to the same period in 2002. The decrease in 2003 was
due primarily to lower distributions related to Catawba River Associates, LLC.
Beginning in October 2002, costs associated with this financing have been
classified as interest expense.
Minority interest expense as shown and discussed in the preceding business
segment EBIT sections includes only minority interest expense related to EBIT of
Duke Energy's joint ventures. It does not include minority interest expense
related to interest and taxes of the joint ventures. Total minority interest
expense related to the joint ventures (including the portion related to interest
and taxes) decreased $28 million for the three months ended March 31, 2003, as
compared to the same period for 2002. The 2003 change was driven by
34
increased earnings from DEFS and from recognizing a full quarter of minority
interest expense in 2003, versus only one month during the first quarter of
2002, from less than wholly owned subsidiaries acquired in the March 2002
acquisition of Westcoast.
The effective tax rate increased to 33.5% for the three months ending March 31,
2003 as compared to 29.3% for the same period in 2002, primarily due to a
benefit from a change in the federal tax law relating to the deduction of
employee stock ownership plan dividends in 2002, and a one-time benefit from a
state tax settlement finalized during the first quarter of 2002.
During the first quarter of 2003, Duke Energy recorded a net-of-tax and minority
interest cumulative effect adjustment for change in accounting principles of
$162 million, or $0.18 per basic share, as a reduction in earnings. The change
in accounting principles included an after-tax and minority interest charge of
$151 million, or $0.17 per basic share, related to the implementation of EITF
Issue No. 02-03 (see Note 2 to the Consolidated Financial Statements) and a
charge of $11 million, or $0.01 per basic share, due to the implementation of
SFAS No. 143, (see Note 2 to the Consolidated Financial Statements).
LIQUIDITY AND CAPITAL RESOURCES
As of March 31, 2003, Duke Energy had $1,109 million in cash and cash
equivalents compared to $857 million as of December 31, 2002. Duke Energy's
working capital was a $163 million deficit as of March 31, 2003, compared to a
$137 million deficit as of December 31, 2002. Duke Energy relies upon cash flows
from operations, as well as borrowings and the sale of assets to fund its
liquidity and capital requirements. A material adverse change in operations or
available financing may impact Duke Energy's ability to fund its current
liquidity and capital resource requirements.
Operating Cash Flows
Net cash provided by operations increased $591 million for the three months
ended March 31, 2003 when compared to the same period in 2002. The increase in
cash provided by operating activities was due primarily to higher cash earnings
plus favorable changes in working capital from 2002. Non-cash items affecting
earnings included an increase in depreciation expense and a charge for the
cumulative effect of changes in accounting principles.
Investing Cash Flows
Net cash used in investing activities decreased $2,894 million for the three
months ended March 31, 2003 when compared to the same period in 2002. Capital
and investment expenditures decreased $2,579 million for the three months ended
March 31, 2003 when compared to the same period in 2002. Decreased capital
expenditures were due primarily to the 2002 acquisition of Westcoast for $1,690
million in cash, net of cash acquired (see Note 3 to the Consolidated Financial
Statements), a decrease in DENA's investments in generating facilities, a
decrease in plant construction costs at Franchised Electric, and a decrease in
investments in property, plant and equipment at Field Services and International
Energy. Investment activities also decreased in 2003 compared to 2002, due
primarily to reduced investments at Other Operations (primarily related to Duke
Capital Partners, LLC) and Natural Gas Transmission's investment in a 50%
interest in Gulfstream Natural Gas System, LLC.
Financing Cash Flows and Liquidity
Duke Energy's consolidated capital structure as of March 31, 2003, including
short-term debt, was 55% debt, 37% common equity, 4% minority interests, 3%
trust preferred securities and 1% preferred stock. Fixed charges coverage ratio,
calculated using the SEC guidelines, was 2.6 times for the three months ended
March 31, 2003 and 2.7 for the three months ended March 31, 2002.
Cash flows from financing activities changed $3,094 million for the three months
ended March 31, 2003 when compared to the same period in 2002. This change is
due primarily to the reduction of outstanding
35
debt during the first quarter of 2003 as compared to the same period in 2002
when Duke Energy acquired Westcoast and financed other business expansion
projects. In addition, this change in cash flows from financing activities is
aligned with Duke Energy's strategy to improve its balance sheet leverage
through the reduction of outstanding debt.
Duke Energy's cash requirements for 2003 are expected to be funded by cash from
operations and the sale of assets, and to be adequate for funding capital
expenditures, dividend payments and repaying approximately $1,800 million of
debt in 2003. During the first four months of 2003, Duke Energy announced or
completed asset sales of approximately $1,100 million in gross proceeds,
including $58 million of assumed debt. In addition, Duke Energy plans to obtain
some funding through common stock issuances in its InvestorDirect Choice Plan (a
stock purchase and dividend reinvestment plan) and employee benefit plans, and
may continue to opportunistically access the capital markets. The ability to
access the capital markets is dependent upon market opportunities presented,
among other factors. Duke Energy does not have any material off-balance sheet
financing entities or structures, except for normal operating lease arrangements
and guarantee contracts (see Note 9 to the Consolidated Financial Statements).
Management believes Duke Energy has adequate financial flexibility and resources
to meet its future needs.
Credit Ratings. In March 2003, Moody's Investor Service (Moody's) placed its
long-term and short-term ratings of Duke Energy, Duke Capital Corporation (a
wholly owned subsidiary of Duke Energy that provides financing and credit
enhancement services for its subsidiaries) and DEFS, and its long-term ratings
of Texas Eastern Transmission, LP and PanEnergy Corp, on review for potential
downgrade. Moody's review was prompted by concerns regarding cash flow coverage
metrics at Duke Capital Corporation and uncertainties associated with
forecasting cash flow contributions from DENA and Duke Energy International,
LLC. Moody's review of DEFS was prompted by perceived pressures on DEFS' debt
coverage ability.
The following table summarizes the credit ratings of Duke Energy, its principal
funding subsidiaries and its trading and marketing subsidiary Duke Energy
Trading and Marketing, LLC, as of March 31, 2003.
- ------------------------------------------------------------------------------------------------------
Credit Ratings Summary as of March 31, 2003
- ------------------------------------------------------------------------------------------------------
Standard Moody's Investor Dominion Bond
and Poors Service Fitch Ratings Rating Service
-------------------------------------------------------------
Duke Energy/a/ A- A3 A- Not applicable
Duke Capital Corporation/a/ BBB+ Baa2 BBB Not applicable
Duke Energy Field Services/a/ BBB Baa2 BBB Not applicable
Texas Eastern Transmission, LP/a/ A- Baa1 BBB+ Not applicable
Westcoast Energy Inc./a/ A- Not applicable Not applicable A(low)
Union Gas Limited/a/ A- Not applicable Not applicable A
Maritimes and Northeast Pipeline, LLC/b/ A A1 Not applicable Not applicable
Maritimes and Northeast Pipeline, LP/b/ A A1 Not applicable A
Duke Energy Trading and Marketing, LLC/c/ BBB Not applicable Not applicable Not applicable
- ------------------------------------------------------------------------------------------------------
/a/ Represents senior unsecured credit rating
/b/ Represents senior secured credit rating
/c/ Represents corporate credit rating
Duke Energy's credit ratings are dependent on, among other factors, the ability
to generate sufficient cash to fund Duke Energy's capital and investment
expenditures and dividends, while strengthening the balance sheet through debt
reductions. If, as a result of market conditions or other factors affecting Duke
Energy's business, Duke Energy is unable to execute its business plan, including
disposition of non-core assets, or if its earnings outlook deteriorates, Duke
Energy's ratings could be further affected.
To date, the impacts of the credit rating downgrades on Duke Energy and its
subsidiaries have been minimal. If further downgrades were to occur and to the
extent that these downgrades placed Duke Energy
36
or its subsidiaries below investment grade, there could be a negative impact on
the respective entity's working capital and terms of trade.
For a discussion of Duke Energy's significant financing activities, credit
facilities and related borrowings and effective SEC and Canadian shelf
registrations, see Note 7 to the Consolidated Financial Statements.
CURRENT ISSUES
For information on current issues related to Duke Energy, see the following
Notes to the Consolidated Financial Statements: Note 5, Regulatory Matters, and
Note 8, Commitments and Contingencies.
New Accounting Standards
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." In June 2002, the Financial Accounting Standards Board (FASB)
issued SFAS No. 146 which addresses accounting for restructuring and similar
costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF
Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." Duke Energy has adopted the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF Issue No.
94-3, a liability for an exit cost was recognized on the date of Duke Energy's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 will affect the timing of recognizing future restructuring costs as well as
the amounts recognized.
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." In April 2003, the FASB issued SFAS No. 149, which amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. SFAS No. 149 clarifies the discussion around initial net investment and
when a derivative contains a financing component, and amends the definition of
the term underlying to conform it to language used in FASB Interpretation No.
45, "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others." In addition, SFAS No.
149 also incorporates certain Derivative Implementation Group Implementation
Issues. The provisions of SFAS No. 149 are effective for contracts entered into
or modified after June 30, 2003, and for hedging relationships designated after
June 30, 2003. The guidance should be applied to hedging relationships on a
prospective basis. Duke Energy is currently assessing the impact SFAS No. 149
will have on its consolidated results of operations, cash flows and financial
position.
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities." In January 2003, the FASB issued FIN 46 which requires the primary
beneficiary of a variable interest entity's activities to consolidate the
variable interest entity. The primary beneficiary is the party that absorbs a
majority of the expected losses and/or receives a majority of the expected
residual returns of the variable interest entity's activities. FIN 46 is
immediately applicable to variable interest entities created, or interests in
variable interest entities obtained, after January 31, 2003. For variable
interest entities created, or interests in variable interest entities obtained,
on or before January 31, 2003, FIN 46 is required to be applied in the first
fiscal year or interim period beginning after June 15, 2003. FIN 46 may be
applied prospectively with a cumulative-effect adjustment as of the date it is
first applied, or by restating previously issued financial statements with a
cumulative-effect adjustment as of the beginning of the first year restated. FIN
46 also requires certain disclosures of an entity's relationship with variable
interest entities. Duke Energy has not identified any variable interest entities
created, or interests in variable entities obtained, after January 31, 2003 and
continues to assess the existence of any interests in variable interest entities
created on or prior to January 31, 2003. It is reasonably possible that Duke
Energy will disclose information about a variable interest entity upon the
application of FIN 46, primarily as the result of investments it has in certain
unconsolidated affiliates. Any significant exposure to losses related to these
entities would be related to guarantee obligations as discussed in Note 9 to the
Consolidated Financial Statements. Duke Energy continues to assess FIN 46 but
does not anticipate that it will have a material impact on its consolidated
results of operations, cash flows or financial position.
37
Subsequent Events
In April 2003, Duke Energy closed on substantially all elements of a transaction
to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada
Marketing and Aux Sable natural gas liquids plant to Enbridge Inc. and Fort
Chicago Energy Partners L.P. for approximately $250 million. This sale resulted
in an immaterial net loss. The transaction was completed except for Duke
Energy's small ownership interest related to the U.S. segment of Alliance
Pipeline, which is expected to close in October 2003 and represents
approximately $11 million in proceeds. Alliance Pipeline extends from Fort St.
John in British Columbia to Chicago, Illinois. The Aux Sable plant extracts
natural gas liquids at the outlet of the Alliance Pipeline in Chicago. Duke
Energy obtained its minority ownership interest in the Alliance natural gas
pipeline, Alliance Canada Marketing and Aux Sable natural gas liquids plant
through its acquisition of Westcoast in 2002.
In April 2003, Duke Energy sold all its Class B units of TEPPCO Partners, L.P.
(TEPPCO) for approximately $114 million. Duke Energy recorded a pre-tax gain of
approximately $11 million on the sale. TEPPCO is a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil.
In April and May 2003, DEFS entered into two separate purchase and sale
agreements by which it will sell one package of assets to Crosstex Energy
Services, L.P. (Crosstex) and a second package of assets to ScissorTail Energy,
LLC (ScissorTail) for a total sales price of approximately $91 million, plus or
minus various adjustments to be made at closing. The gain on the sale will be
approximately $17 million (at Duke Energy's approximately 70% share). The assets
to be sold to Crosstex consist of the AIM Pipeline System in Mississippi; a
12.4% interest in the Seminole gas processing plant in Texas; the Conroe gas
plant and gathering system in Texas; the Black Warrior pipeline system in
Alabama; and two smaller systems - Aurora Centana and Cadeville in Louisiana.
The assets to be sold to ScissorTail consist of various gas processing plants
and gathering pipeline in eastern Oklahoma. The transactions are expected to
close by June 30, 2003. The sale to Crosstex is subject to regulatory approvals.
For information on subsequent events related to regulatory matters, see Note 5
to the Consolidated Financial Statements, Notices of Proposed Rulemaking
section. For information on subsequent events related to litigation and
contingencies see Note 8 to the Consolidated Financial Statements, Litigation
section. For information on subsequent events related to debt and other
financing matters, see Note 7 to the Consolidated Financial Statements.
38
Item 3. Quantitative and Qualitative Disclosures about Market Risk
As of March 31, 2003, there have been no material changes in Duke Energy's
qualitative and quantitative disclosures about market risk since December 31,
2002. See "Management's Discussion and Analysis of Results of Operations and
Financial Condition, Quantitative and Qualitative Disclosures About Market Risk"
in Duke Energy's Form 10-K for December 31, 2002 for information on market risk.
Item 4. Controls and Procedures.
During April and May 2003, Duke Energy's management, including the Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness of
Duke Energy's disclosure controls and procedures as defined in Exchange Act Rule
13a-14. Based on that evaluation, they concluded that the disclosure controls
and procedures are effective in ensuring that all material information required
to be filed in this quarterly report has been made known to them in a timely
fashion. The required information was effectively recorded, processed,
summarized and reported within the time period necessary to prepare this
quarterly report. Duke Energy's disclosure controls and procedures are effective
in ensuring that information required to be disclosed in Duke Energy's reports
under the Exchange Act are accumulated and communicated to management, including
the Chief Executive Officer and the Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure. There have been no
significant changes in internal controls, or in factors that could significantly
affect internal controls, after the Chief Executive Officer and Chief Financial
Officer completed their evaluation.
39
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
In late 1999, Duke Energy discovered that operations and maintenance personnel
at its Moss Landing, California facility were occasionally "backflushing," a
practice initially implemented by the facility's prior owner, to remove debris
from the inlet side of the condensers. The flow of wastewater from this practice
was not specifically authorized in the facility's discharge permit. Upon its
discovery, Duke Energy promptly reported the noncompliance to the California
Regional Water Quality Control Board (Control Board) and stopped the discharges.
After ongoing discussions of this matter, Duke Energy and the Control Board have
agreed to the terms of a stipulated order with a civil penalty of $250,000, the
bulk of which will be paid as a Supplemental Environmental Project. The Control
Board is expected to formally approve the stipulated order in May 2003.
For additional information concerning litigation and other contingencies, see
Note 8 to the Consolidated Financial Statements, "Commitments and
Contingencies;" and Item 3, "Legal Proceedings," and Note 16 to the Consolidated
Financial Statements, "Commitments and Contingencies," in Duke Energy's Form
10-K for December 31, 2002, which are incorporated herein by reference.
Management believes that the final disposition of these proceedings will have no
material adverse effect on Duke Energy's consolidated results of operations,
cash flows or financial position.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of the security holders of Duke Energy
during the first quarter of 2003.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
Exhibit
Number
- --------
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
The total amount of securities of the registrant or its subsidiaries authorized
under any instrument with respect to long-term debt not filed as an exhibit does
not exceed 10% of the total assets of the registrant and its subsidiaries on a
consolidated basis. The registrant agrees, upon request of the Securities and
Exchange Commission, to furnish copies of any or all of such instruments.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed on February 18, 2003 contained
disclosures under Item 5, "Other Events and Regulation FD Disclosure," and Item
7, "Financial Statements and Exhibits."
40
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 ENERGY CORPORATION
Date: May 15, 2003 /s/ Robert P. Brace
-----------------------------
Robert P. Brace
Executive Vice President and
Chief Financial Officer
Date: May 15, 2003 /s/ Keith G. Butler
-----------------------------
Keith G. Butler
Senior Vice President and
Controller
41
CERTIFICATIONS
I, Richard B. Priory, certify that:
1) I have reviewed this quarterly report on Form 10-Q of Duke Energy
Corporation;
2) Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 15, 2003 /s/ Richard B. Priory
-----------------------------
Richard B. Priory
Chairman of the Board
and Chief Executive Officer
42
CERTIFICATIONS
I, Robert P. Brace, certify that:
1) I have reviewed this quarterly report on Form 10-Q of Duke Energy
Corporation;
2) Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 15, 2003 /s/ Robert P. Brace
-----------------------------
Robert P. Brace
Executive Vice President and
Chief Financial Officer
43