-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PfD51UJ75fEXNdP5KyUi7lT2Ge59BQLJqBMynFMRNFBgw/cD0nMLQ+l2E9+nf7U9 6GhqlRAeNY9e6Zdm2dNanA== 0000950168-02-002420.txt : 20020814 0000950168-02-002420.hdr.sgml : 20020814 20020814150638 ACCESSION NUMBER: 0000950168-02-002420 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DUKE ENERGY CORP CENTRAL INDEX KEY: 0000030371 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 560205520 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-04928 FILM NUMBER: 02735395 BUSINESS ADDRESS: STREET 1: 526 SOUTH CHURCH STREET CITY: CHARLOTTE STATE: NC ZIP: 28202 BUSINESS PHONE: 7045940887 MAIL ADDRESS: STREET 1: 526 S. CHURCH ST. CITY: CHARLOTTE STATE: NC ZIP: 28202 FORMER COMPANY: FORMER CONFORMED NAME: DUKE POWER CO /NC/ DATE OF NAME CHANGE: 19920703 10-Q 1 d10q.txt DUKE ENERGY CORPORATION ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________ FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarter Ended June 30, 2002 Commission File Number 1-4928 DUKE ENERGY CORPORATION (Exact name of Registrant as Specified in its Charter) North Carolina 56-0205520 (State or Other Jurisdiction of Incorporation) (IRS Employer Identification No.) 526 South Church Street Charlotte, NC 28202-1904 (Address of Principal Executive Offices) (Zip code) 704-594-6200 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. 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 July 31, 2002.....833,179,657 DUKE ENERGY CORPORATION FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2002 INDEX
Item - ---- Page - ---- PART I. FINANCIAL INFORMATION 1. Financial Statements ................................................................................ 1 Consolidated Statements of Income for the Three and Six Months Ended June 30, 2002 and 2001 ...................................................................... 1 Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 ........................... 2 Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2002 and 2001 ........... 4 Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2002 and 2001 ...................................................................... 5 Notes to Consolidated Financial Statements ...................................................... 6 2. Management's Discussion and Analysis of Results of Operations and Financial Condition ............... 22 PART II. OTHER INFORMATION 1. Legal Proceedings ................................................................................... 45 4. Submission of Matters to a Vote of Security Holders ................................................. 45 6. Exhibits and Reports on Form 8-K .................................................................... 46 Signatures .......................................................................................... 47
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 Duke Energy's reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as "may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "potential," "plan," "forecast" and other similar words. Those statements represent our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include: . state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries; . the outcomes of litigation and regulatory proceedings or inquiries; . industrial, commercial and residential growth in our service territories; . the weather and other natural phenomena; . the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates; . changes in environmental and other laws and regulations to which we and our subsidiaries are i subject or other external factors over which we have no control; . the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions; . the level of creditworthiness of counterparties to our transactions; . the amount of collateral required to be posted from time to time in our transactions; . growth in opportunities for our business units, including the timing and success of efforts to develop domestic and international power, pipeline, gathering, processing and other infrastructure projects; . the performance of electric generation, pipeline and gas processing facilities; . the extent of success in connecting natural gas supplies to gathering and processing systems and in connecting and expanding gas and electric markets; and . the effect of accounting policies issued periodically by accounting standard-setting bodies. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. ii PART I. FINANCIAL INFORMATION Item 1. Financial Statements. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (In millions, except per share amounts)
Three Months Ended Six Months Ended June 30, June 30, --------------------- --------------------- 2002 2001 2002 2001 --------- ---------- --------- ---------- Operating Revenues Sales, trading and marketing of natural gas and petroleum products $ 10,676 $ 7,809 $ 16,305 $ 19,260 Trading and marketing of electricity 3,853 5,865 7,880 9,168 Generation, transmission and distribution of electricity 958 1,238 2,661 2,498 Transportation and storage of natural gas 447 233 773 479 Other 399 435 599 666 --------- ---------- --------- ---------- Total operating revenues 16,333 15,580 28,218 32,071 --------- ---------- --------- ---------- Operating Expenses Natural gas and petroleum products purchased 10,278 7,599 15,740 18,679 Net interchange and purchased power 3,442 5,484 7,636 8,163 Operation and maintenance 859 964 1,711 1,841 Fuel used in electric generation 237 223 452 465 Depreciation and amortization 397 326 741 642 Property and other taxes 132 104 259 219 --------- ---------- --------- ---------- Total operating expenses 15,345 14,700 26,539 30,009 --------- ---------- --------- ---------- Operating Income 988 880 1,679 2,062 Other Income and Expenses 59 22 129 94 Interest Expense 264 202 453 415 Minority Interest Expense 62 45 94 205 --------- ---------- --------- ---------- Earnings Before Income Taxes 721 655 1,261 1,536 Income Taxes 247 236 405 563 --------- ---------- --------- ---------- Income Before Cumulative Effect of Change in Accounting Principle 474 419 856 973 Cumulative Effect of Change in Accounting Principle, net of tax - - - (96) --------- ---------- --------- ---------- Net Income 474 419 856 877 Preferred and Preference Stock Dividends 4 4 7 8 --------- ---------- --------- ---------- Earnings Available For Common Stockholders $ 470 $ 415 $ 849 $ 869 ========= ========== ========= ========== Common Stock Data Weighted-average shares outstanding 831 773 809 759 Earnings per share (before cumulative effect of change in accounting principle) Basic $ 0.57 $ 0.54 $ 1.05 $ 1.27 Diluted $ 0.56 $ 0.53 $ 1.04 $ 1.26 Earnings per share Basic $ 0.57 $ 0.54 $ 1.05 $ 1.14 Diluted $ 0.56 $ 0.53 $ 1.04 $ 1.13 Dividends per share $ 0.550 $ 0.550 $ 0.825 $ 0.825
See Notes to Consolidated Statements. 1 CONSOLIDATED BALANCE SHEETS (In millions)
June 30, December 31, 2002 2001 (Unaudited) -------------- -------------- ASSETS Current Assets Cash and cash equivalents $ 87 $ 290 Receivables 6,597 5,301 Inventory 1,174 1,017 Current portion of purchased capacity costs 173 160 Unrealized gains on mark-to-market and hedging transactions 3,326 2,326 Other 746 451 -------------- -------------- Total current assets 12,103 9,545 -------------- -------------- Investments and Other Assets Investments in affiliates 2,256 1,480 Nuclear decommissioning trust funds 680 716 Pre-funded pension costs 339 313 Goodwill, net of accumulated amortization 4,125 1,730 Notes receivable 641 576 Unrealized gains on mark-to-market and hedging transactions 5,303 3,117 Other 1,384 1,299 -------------- -------------- Total investments and other assets 14,728 9,231 -------------- -------------- Property, Plant and Equipment Cost 48,219 39,464 Less accumulated depreciation and amortization 11,835 11,049 -------------- -------------- Net property, plant and equipment 36,384 28,415 -------------- -------------- Regulatory Assets and Deferred Debits Purchased capacity costs 65 189 Deferred debt expense 228 203 Regulatory asset related to income taxes 546 510 Other 1,138 282 -------------- -------------- Total regulatory assets and deferred debits 1,977 1,184 -------------- -------------- Total Assets $ 65,192 $ 48,375 ============== ==============
See Notes to Consolidated Financial Statements. 2 CONSOLIDATED BALANCE SHEETS (In millions)
June 30, December 31, 2002 2002 (Unaudited) --------------- -------------- LIABILITIES AND COMMON STOCKHOLDERS' EQUITY Current Liabilities Accounts payable $ 5,254 $ 4,231 Notes payable and commercial paper 2,673 1,603 Taxes accrued 857 443 Interest accrued 335 239 Current maturities of long-term debt and preferred stock 1,033 274 Unrealized losses on mark-to-market and hedging transactions 2,794 1,519 Other 1,800 2,118 -------------- -------------- Total current liabilities 14,746 10,427 -------------- -------------- Long-term Debt 18,319 12,321 -------------- -------------- Deferred Credits and Other Liabilities Deferred income taxes 4,696 4,307 Investment tax credit 182 189 Nuclear decommissioning costs externally funded 680 716 Environmental cleanup liabilities 50 85 Unrealized losses on mark-to-market and hedging transactions 3,914 2,212 Other 3,083 1,542 -------------- -------------- Total deferred credits and other liabilities 12,605 9,051 -------------- -------------- Commitments and Contingencies Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Energy Corporation or Subsidiaries 1,407 1,407 -------------- -------------- Minority Interests in Financing Subsidiary 1,025 1,025 -------------- -------------- Minority Interests 1,971 1,221 -------------- -------------- Preferred and Preference Stock Preferred and preference stock with sinking fund requirements 23 25 Preferred and preference stock without sinking fund requirements 209 209 -------------- -------------- Total preferred and preference stock 232 234 -------------- -------------- Common Stockholders' Equity Common stock, no par, 2 billion shares authorized; 832 million and 777 million shares outstanding at June 30, 2002 and December 31, 2001, 8,184 6,217 respectively Retained earnings 6,553 6,292 Accumulated other comprehensive income 150 180 -------------- -------------- Total common stockholders' equity 14,887 12,689 -------------- -------------- Total Liabilities and Common Stockholders' Equity $ 65,192 $ 48,375 ============== ==============
See Notes to Consolidated Financial Statements. 3 CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In millions)
Six Months Ended June 30, ----------------------- 2002 2001 ----------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 856 $ 877 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization 789 718 Cumulative effect of change in accounting principle - 96 Gain on sale of subsidiaries (29) - Deferred income taxes 14 266 Purchased capacity levelization 88 78 (Increase) decrease in Net unrealized mark-to-market and hedging transactions (27) (211) Receivables (4) (204) Inventory 20 (109) Other current assets (212) 356 Increase (decrease) in Accounts payable 582 (149) Taxes accrued 352 125 Interest accrued 48 46 Other current liabilities (431) 426 Other, assets (162) 131 Other, liabilities (338) (235) ---------- ---------- Net cash provided by operating activities 1,546 2,211 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (2,685) (2,364) Investment expenditures (615) (629) Acquisition of Westcoast Energy, Inc., net of cash acquired (1,690) - Proceeds from the sale of subsidiaries 133 - Notes receivable 134 45 Other 76 675 ---------- ---------- Net cash used in investing activities (4,647) (2,273) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from the issuance of Long-term debt 2,743 1,664 Common stock and stock options 211 1,338 Payments for the redemption of long-term debt (523) (461) Net change in notes payable and commercial paper 688 (1,417) Contributions from minority interests 261 - Dividends paid (459) (419) Other (23) (24) ---------- ---------- Net cash provided by financing activities 2,898 681 ---------- ---------- Net (decrease) increase in cash and cash equivalents (203) 619 Cash and cash equivalents at beginning of period 290 622 ---------- ---------- Cash and cash equivalents at end of period $ 87 $ 1,241 ========== ========== Supplemental Disclosures Cash paid for interest, net of amount capitalized $ 344 $ 387 Cash paid for income taxes $ 10 $ 111 Acquisition of Westcoast Energy, Inc. Fair value of assets acquired $ 9,480 Liabilities assumed, including debt and minority interests 8,387 Issuance of common stock 1,797
See Notes to Consolidated Financial Statements. 4 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (In millions)
Three Months Ended Six Months Ended June 30, June 30, --------------------------- ------------------------- 2002 2001 2002 2001 ------------ ------------ ----------- ----------- Net Income $ 474 $ 419 $ 856 $ 877 Other comprehensive income (loss), net of tax Cumulative effect of change in accounting principle - - - (921) Foreign currency translation adjustments (101) (47) (125) (188) Net unrealized (losses) gains on cash flow hedges (81) 1,509 181 1,153 Reclassification into earnings 26 301 (86) 479 ------------ ------------ ----------- ----------- Total other comprehensive (loss) income (156) 1,763 (30) 523 ------------ ------------ ----------- ----------- Total Comprehensive Income $ 318 $ 2,182 $ 826 $ 1,400 ============ ============ =========== ===========
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 seven 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, storage and distribution of natural gas for customers throughout the east coast and southern portion of the U.S. and Canada. Natural Gas Transmission provides gas gathering, processing and transportation services to customers located in British Columbia, Canada and in the Pacific northwest region of the U.S. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. Duke Energy acquired Westcoast Energy, Inc. (Westcoast) on March 14, 2002 (see Note 3). Interstate natural gas transmission and storage operations in the U.S. are subject to the FERC's rules and regulations while natural gas gathering, processing, transmission, distribution and storage operations in Canada are subject to the rules and regulations of the National Energy Board, the Ontario Energy Board and the British Columbia Utilities Commission. Field Services gathers, processes, transports, markets and stores natural gas and produces, transports, markets and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC, which is approximately 30% owned by Phillips Petroleum. Field Services operates gathering systems in western Canada and 11 contiguous states in the U.S. Those systems serve major natural gas-producing regions in the Rocky Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, and onshore and offshore Gulf Coast areas. Duke Energy North America (DENA) develops, operates and manages merchant generation facilities and engages in commodity sales and services related to natural gas and electric power. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil Corporation. Prior to April 1, 2002, the DENA business segment was combined with Duke Energy Merchants Holdings, LLC (DEM) to form a segment called North American Wholesale Energy. As of June 30, 2002, management combined DEM with the Other Energy Services segment. Management separated DENA for increased reporting transparency. Previous periods have been reclassified to conform to the current presentation. Beginning August 1, 2002, Duke Energy's North American trading and marketing functions currently in DENA and DEM, including DETM and the Canadian trading operations, will be consolidated into one group. International Energy develops, operates and manages natural gas transportation and power generation facilities and engages in energy trading and marketing of natural gas and electric power. It conducts operations primarily through Duke Energy International, LLC and its activities target the Latin American, Asia-Pacific and European regions. Other Energy Services is composed of diverse energy businesses, operating primarily through DEM, Duke/Fluor Daniel (D/FD) and Energy Delivery Services (EDS). DEM engages in commodity buying and selling, and risk management and financial services in the energy commodity markets other than natural gas and power (such as refined products, liquefied petroleum gas, residual fuels, crude oil and coal). 6 D/FD provides comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. It is a 50/50 partnership between 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. It was formed in the second quarter of 2002 from the power delivery services component of Duke Engineering & Services, Inc. (DE&S). This segment was excluded from the sale of DE&S on April 30, 2002. Other Energy Services also retained the portion of DukeSolutions, Inc. (DukeSolutions) that was not sold on May 1, 2002. DE&S and DukeSolutions were included in Other Energy Services through the date of their sale. For additional information on the sale of DE&S and DukeSolutions, see Note 3. Duke Ventures is composed of other diverse businesses, operating primarily through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet) and Duke Capital Partners, LLC (DCP). Crescent develops high-quality commercial, residential and multi-family real estate projects and manages land holdings primarily in the southeastern and southwestern U.S. DukeNet develops and manages fiber optic communications systems for wireless, local and long distance communications companies and selected educational, governmental, financial and health care entities. DCP, a wholly owned merchant banking company, provides debt and equity capital and financial advisory services primarily to the energy industry. 2. Summary of Significant Accounting Policies Consolidation. The Consolidated Financial Statements include the accounts of 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 and the timing of maintenance on electric generating units. Earnings Per Common Share. Basic earnings per share is based on a weighted average of common shares outstanding. Diluted earnings per share reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, restricted stock awards, performance 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.
- -------------------------------------------------------------------------------------------------- Denominator for Earnings per Share (in millions) - -------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------- 2002 2001 2002 2001 Denominator for basic earnings per share (weighted average shares outstanding) \\a\\ 830.6 773.0 809.1 759.2 Assumed exercise of dilutive securities or other agreements to issue common stock 3.6 6.1 3.8 5.7 ---------------------------------------------- Denominator for diluted earnings per share 834.2 779.1 812.9 764.9 - --------------------------------------------------------------------------------------------------
\\a\\ Increase in shares due primarily to Westcoast acquisition (See Note 3) Options, restricted stock awards, performance awards and phantom stock awards to purchase 19 million shares of common stock as of June 30, 2002, were not included in the computation of diluted earnings per share because the exercise prices were greater than the average market price of the common shares during the period. As of June 30, 2001, all options, restricted stock awards, performance awards and phantom stock awards were included in the computation of diluted earnings per share because none of the exercise 7 prices were greater than the average market price of the common shares during the period. Accounting for Hedges and Trading Activities. All derivatives not qualifying for the normal purchases and sales exemption under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. On the date that swaps, futures, forwards or option contracts are entered into, Duke Energy designates the derivative as either held for trading (trading instrument); as a hedge of a forecasted transaction or future cash flows (cash flow hedge); as a hedge of a recognized asset, liability or firm commitment (fair value hedge); or as a normal purchase or sale contract. For hedge contracts, Duke Energy formally assesses, both at the hedge contract's inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. In accordance with SFAS No. 133, a gain on the time value of options of $1 million was excluded in the assessment and measurement of hedge effectiveness for the three months ended June 30, 2002. When available, quoted market prices or prices obtained through external sources are used to verify a contract's fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. As of June 30, 2002, 47% of the trading contracts' fair value was determined using market prices and other external sources and 53% was determined using pricing models. Values are adjusted to reflect the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. Trading. Prior to settlement of any energy contract held for trading purposes, a favorable or unfavorable price movement is reported as Natural Gas and Petroleum Products Purchased, or Net Interchange and Purchased Power, in the Consolidated Statements of Income. An offsetting amount is recorded on the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. When a contract to sell is physically settled, the fair value entries are reversed and the gross amount invoiced to the customer is included as Sales, Trading and Marketing of Natural Gas and Petroleum Products, or Trading and Marketing of Electricity, in the Consolidated Statements of Income. Similarly, when a contract to purchase is physically settled, the purchase price is included as Natural Gas and Petroleum Products Purchased, or Net Interchange and Purchased Power, in the Consolidated Statements of Income. If a contract is financially settled, the unrealized gain or loss on the Consolidated Balance Sheets is reversed and reclassified to a receivable or payable account. For income statement purposes, financial settlement has no revenue presentation effect on the Consolidated Statements of Income. Cash Flow Hedges. Changes in the fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive Income as Other Comprehensive Income (OCI) until earnings are affected by the hedged item. Settlement amounts and ineffective portions of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Income in the same accounts as the item being hedged. Duke Energy discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur. Gains and losses that were accumulated in OCI will be immediately 8 recognized in current-period earnings in those instances. Fair Value Hedges. Duke Energy enters into interest rate swaps to convert some of its fixed-rate long-term debt to floating-rate long-term debt and designates such interest rate swaps as fair value hedges. Duke Energy also enters into electricity derivative instruments such as swaps, futures and forwards to manage the fair value risk associated with some of its unrecognized firm commitments to sell generated power due to changes in the market price of power. Upon designation of such derivatives as fair value hedges, prospective changes in the fair value of the derivative and the hedged item are recognized in current earnings in a manner consistent with the earnings effect of the hedged risk. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. New Accounting Standards. Duke Energy adopted SFAS No. 142, "Goodwill and Other Intangible Assets," as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. Duke Energy did not recognize any material impairment due to the implementation of SFAS No. 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon reassessment. No adjustments to intangibles were identified by Duke Energy at transition. The following table shows what net income and earnings per share would have been if amortization (including any related tax effects) related to goodwill that is no longer being amortized had been excluded from prior periods.
- ---------------------------------------------------------------------------------------------------------- Goodwill - Adoption of SFAS No. 142 (in millions, except per share amounts) - ---------------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ----------------------------------------------------- 2002 2001 2002 2001 ----------------------------------------------------- Net Income Reported net income $ 474 $ 419 $ 856 $ 877 Add back: Goodwill amortization, net of tax - 23 - 38 ---------------------------------------------------- Adjusted net income $ 474 $ 442 $ 856 $ 915 ---------------------------------------------------- Basic earnings per share Reported earnings per share $0.57 $0.54 $1.05 $1.14 Goodwill amortization - 0.03 - 0.05 Adjusted earnings per share $0.57 $0.57 $1.05 $1.19 Diluted earnings per share Reported earnings per share $0.56 $0.53 $1.04 $1.13 Goodwill amortization - 0.03 - 0.05 Adjusted earnings per share $0.56 $0.56 $1.04 $1.18 - ---------------------------------------------------------------------------------------------------------
9 The changes in the carrying amount of goodwill for the six months ended June 30, 2002 and June 30, 2001 are as follows:
- --------------------------------------------------------------------------------------------------------------- Goodwill (in millions) - --------------------------------------------------------------------------------------------------------------- Balance Acquired Balance December 31, 2001 Goodwill Other June 30, 2002 --------------------- ------------------- ----------------- ------------------- Natural Gas Transmission $ 481 $2,470 $ - $2,951 Field Services 571 - (90) 481 Duke Energy North America 91 - 18 109 International Energy 427 - - 427 Other Energy Services 6 - (3) 3 Other Operations 154 - - 154 --------------------- ------------------- ----------------- ------------------- Total consolidated $1,730 $2,470 $ (75) $4,125 - ----------------------------------------------------- ------------------- ----------------- ------------------- Balance Acquired Balance December 31, 2000 Goodwill Other June 30, 2001 --------------------- ------------------- ----------------- ------------------- Natural Gas Transmission $ 299 $ - $ 123 $ 422 Field Services 507 - (26) 481 Duke Energy North America 73 - (4) 69 International Energy 457 6 (51) 412 Other Energy Services 48 - (4) 44 Other Operations 182 - (13) 169 --------------------- ------------------- ----------------- ------------------- Total consolidated $1,566 $ 6 $ 25 $1,597 - ----------------------------------------------------- ------------------- ----------------- -------------------
Duke Energy adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" on January 1, 2002. The new rules supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale or as a discontinued operation. Adoption of the new standard had no material adverse effect on Duke Energy's consolidated results of operations or financial position. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is increased due to the passage of time based on the time value of money until the obligation is settled. Duke Energy is required and plans to adopt the provisions of SFAS No. 143 as of January 1, 2003. To accomplish this, Duke Energy must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Additionally, Duke Energy will be required to develop processes to track and monitor these obligations. Because of the effort needed to comply with the adoption of SFAS No. 143, Duke Energy is currently assessing the new standard but has not yet determined the impact on its consolidated results of operations, cashflows or financial position. 10 In June 2002, the FASB's Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and EITF No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods must be reclassified to reflect presentation on a net basis. Also, companies must disclose volumes of physically settled energy trading contracts. Duke Energy is evaluating the impact of this new consensus on the presentation of its Consolidated Statements of Income, but believes it will have a material impact on total revenues and expenses. The partial consensus will have no impact on current or prior net income. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Duke Energy will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. Reclassifications. Certain prior period amounts in the Consolidated Financial Statements and Note 5 have been reclassified to conform to the current presentation. 3. Business Acquisitions and Dispositions Business Acquisitions. Using the purchase method for acquisitions, Duke Energy consolidates assets and liabilities as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on asset and liability valuations becomes available within one year after the acquisition. Acquisition of Westcoast Energy Inc. On March 14, 2002, Duke Energy acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a wholly owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by Duke Energy. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. Westcoast, headquartered in Vancouver, British Columbia, is a North American energy company with interests in natural gas gathering, processing, transmission, storage and distribution, as well as power generation and international energy businesses. In the transaction, a Duke Energy subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock), and approximately $1.8 billion in cash. Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities in November 2001 along with incremental commercial paper. Duke Energy plans to retire the commercial paper later in 2002 and replace it with permanent capital in the form of equity or 11 equity linked securities. The timing for the equity or equity linked securities will be dependent on the market opportunities presented. The Westcoast acquisition was accounted for using the purchase method of accounting, and goodwill totaling approximately $2.5 billion was recorded in the transaction. The following unaudited pro forma consolidated financial results are presented as if the acquisition had taken place at the beginning of the periods presented.
- ------------------------------------------------------------------------------------------------------------- Consolidated Pro Forma Results for Duke Energy, including Westcoast (in millions, except per share amounts) - ------------------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------------- 2002 2001 2002 2001 ------------------------------------------------------------- Income Statement Data Operating revenues $16,333 $16,883 $29,500 $36,754 Income before cumulative effect of change in accounting principle 474 504 893 1,111 Cumulative effect of change in accounting principle, net of tax - - - (96) Preferred and preference stock dividends 4 4 7 8 Earnings available to common stockholders 470 500 886 1,007 Common Stock Data Weighted-average shares outstanding 831 823 829 809 Earnings per share (before cumulative effect of change in accounting principle) Basic $ 0.57 $ 0.61 $ 1.07 $ 1.36 Diluted $ 0.56 $ 0.60 $ 1.06 $ 1.35 Earnings per share Basic $ 0.57 $ 0.61 $ 1.07 $ 1.24 Diluted $ 0.56 $ 0.60 $ 1.06 $ 1.23 - -------------------------------------------------------------------------------------------------------------
Dispositions. DE&S. On April 30, 2002, Duke Energy completed the sale of portions of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier) for $74 million. Two components of DE&S were not part of the sale and remain components of Other Energy Services. Duke Energy established EDS in the second quarter of 2002 from the transmission and distribution services component of DE&S ; it will continue to supply transmission, distribution and substation services to customers. Leadership of the U.S. Department of Energy Mixed Oxide Fuel project also remains with Duke Energy. Operating revenues in 2002 include the resulting pre-tax gain of $21 million on the sale of DE&S, or an after-tax gain of $0.02 per basic share. DukeSolutions. On May 1, 2002, Duke Energy completed the sale of portions of DukeSolutions to Ameresco Inc. for $6 million. The portions that were not sold remain a component of Other Energy Services. Operating expenses in 2002 include the resulting pre-tax loss on the sale of DukeSolutions of $22 million, or an after-tax loss of $0.02 per basic share. 4. Derivative Instruments, Hedging Activities and Credit Risk Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, processing and marketing activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of its future sales and generation revenues. Duke Energy uses commodity instruments, consisting of swaps, futures, 12 forwards and collared options, as cash flow hedges for natural gas, electricity and NGL transactions. Duke Energy is hedging exposures to the price variability of these commodities for a maximum of 30 years. For the six months ended June 30, 2002, the ineffective portion of commodity cash flow hedges was an after-tax net loss of $14 million and this amount was not material for the six months ended June 30, 2001. As of June 30, 2002, $298 million of after-tax deferred net gains on derivative instruments were accumulated on the Consolidated Balance Sheet in a separate component of stockholders equity, OCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in OCI will likely change prior to its reclassification into earnings. Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Energy actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, consisting of swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power and natural gas sales. Duke Energy is hedging exposures to the market risk of such items for a maximum of 23 years. For the three and six months ended June 30, 2002 and 2001, the ineffective portion of commodity fair value hedges was not material. Trading Contracts. Duke Energy provides energy supply, structured origination, trading and marketing, risk management and commercial optimization services to large energy customers, energy aggregators and other wholesale companies. These services require Duke Energy to use natural gas, electricity, NGL and transportation derivatives and contracts that expose it to a variety of market risks. Duke Energy manages its trading exposure with strict policies that limit its market risk and require daily reporting of potential financial exposure to management. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement. Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy to risk as a result of its issuance of variable-rate debt, fixed-to-floating interest rate swaps, commercial paper and auction rate preferred stock. Duke Energy manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, options, swaptions and lock agreements to manage and mitigate interest rate risk exposure. For the three and six months ended June 30, 2002 and 2001, Duke Energy's existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position. Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy also uses foreign currency derivatives to manage its risk related to foreign currency fluctuations. As of June 30, 2002, an unrealized loss on foreign exchange contracts of $40 million was included in the cumulative translation adjustment, a separate component of OCI, as a hedge of our net investment in Canada. For the three and six months ended June 30, 2001, the impact of Duke Energy's foreign currency derivative instruments was not material to its consolidated results of operations, cash flows or financial position. Credit Risk. Duke Energy's principal customers for power and natural gas marketing services are industrial end-users, marketers and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers throughout these regions. These concentrations of customers may 13 affect Duke Energy's overall credit risk in that some customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, Duke Energy analyzes the counterparties' financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. Duke Energy frequently uses master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Despite the current challenges in the energy sector, management believes the credit risk management process described above is operating effectively. As of June 30, 2002, Duke Energy held cash or letters of credit of $932 million to secure future performance, and had deposited with counterparties $161 million of such collateral to secure its obligations to provide future services. Collateral amounts held or posted vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return held collateral and post additional collateral if price movements adversely impact the value of open contracts or positions. Duke Energy's and its counterparties' publicly disclosed credit ratings impact the amounts of additional collateral to be posted. The change in market value of New York Mercantile Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of Duke Energy's counterparties. As of June 30, 2002, Duke Energy had a pre-tax bad debt provision of $90 million related to receivables for energy sales in California. Following the bankruptcy of Enron Corporation, Duke Energy terminated substantially all contracts with Enron Corporation and its affiliated companies (collectively, Enron). As a result, in 2001 Duke Energy recorded, as a charge, a non-collateralized accounting exposure of $43 million. The $43 million non-collateralized accounting exposure was composed of charges of $24 million at Other Energy Services, $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment's earnings in 2001. Duke Energy's determination of its bankruptcy claims against Enron is still under review, and its claims made in the bankruptcy case are likely to exceed $43 million. Any bankruptcy claims that exceed this amount would primarily relate to termination and settlement rights under contracts and transactions with Enron that would have been recognized in future periods, and not in the historical periods covered by the financial statements to which the $43 million charge relates. Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. Duke Energy has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Duke Energy affiliate, Companhia de Geracao de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by Duke Energy's predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Duke Energy affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Duke Energy affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of Duke Energy to cover its exposure. 14 5. Business Segments Duke Energy's reportable segments offer different products and services and are managed separately as strategic business units. Prior to April 1, 2002, the DENA business segment was combined with DEM to form a segment called North American Wholesale Energy. As of June 30, 2002, management combined DEM with the Other Energy Services segment. Management separated DENA for increased reporting transparency. Previous periods have been reclassified to conform to the current presentation. Beginning August 1, 2002, Duke Energy's North American trading and marketing functions currently in DENA and DEM, including DETM and the Canadian trading operations, will be consolidated into one group. Accounting policies for Duke Energy's segments are the same as those described in Note 2. Management evaluates segment performance based on earnings before interest and taxes (EBIT) after deducting minority interests. The following table shows how EBIT is calculated. - -------------------------------------------------------------------------------- Reconciliation of Operating Income to EBIT (in millions) - --------------------------------------------------------------------------------
Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------------- 2002 2001 2002 2001 ------------------------------------------------------------- Operating income $ 988 $880 $1,679 $2,062 Plus: Other income and expenses 59 22 129 94 ------------------------------------------------------------- EBIT $ 1,047 $902 $1,808 $2,156 - -------------------------------------------------------------------------------------------------------------
EBIT is the primary performance measure used by management to evaluate segment performance. As an indicator of Duke Energy's operating performance or liquidity, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles. Duke Energy's EBIT may not be comparable to a similarly titled measure of another company. 15 In the accompanying table, EBIT includes the profit on intersegment sales at prices representative of arms length transactions. Capital and investment expenditures are gross of cash received from acquisitions.
- -------------------------------------------------------------------------------------------------------------------- Business Segment Data (in millions) - -------------------------------------------------------------------------------------------------------------------- Depreciation Capital and Unaffiliated Intersegment Total and Investment Revenues Revenues Revenues EBIT Amortization Expenditures --------------------------------------------------------------------------------- Three Months Ended June 30, 2002 Franchised Electric $ 1,162 $ - $ 1,162 $ 389 $154 $ 323 Natural Gas Transmission 636 42 678 312 90 253 Field Services 1,498 314 1,812 41 71 74 Duke Energy North America 9,423 20 9,443 196 39 785 International Energy 1,189 1 1,190 67 29 136 Other Energy Services 2,314 74 2,388 72 7 13 Duke Ventures 111 - 111 56 5 158 Other Operations \\a\\ - (6) (6) (128) 2 (36) Eliminations and minority interests - (445) (445) 42 - - --------------------------------------------------------------------------------- Total consolidated $ 16,333 $ - $ 16,333 $ 1,047 $397 $ 1,706 - -------------------------------------------------------------------------------------------------------------------- Three Months Ended June 30, 2001 Franchised Electric $ 1,154 $ - $ 1,154 $ 361 $146 $ 275 Natural Gas Transmission 229 35 264 142 36 207 Field Services 2,255 283 2,538 84 70 261 Duke Energy North America 9,915 136 10,051 272 23 830 International Energy 399 - 399 68 23 135 Other Energy Services 1,530 61 1,591 (12) 15 20 Duke Ventures 98 - 98 36 5 189 Other Operations \\a\\ - 30 30 (73) 8 34 Eliminations and minority interests - (545) (545) 24 - - --------------------------------------------------------------------------------- Total consolidated $ 15,580 $ - $ 15,580 $ 902 $326 $ 1,951 - --------------------------------------------------------------------------------------------------------------------
\\a\\ Other operations primarily includes certain unallocated corporate costs. 16
- ---------------------------------------------------------------------------------------------------------- Business Segment Data (in millions) - ---------------------------------------------------------------------------------------------------------- Depreciation Capital and Unaffiliated Intersegment Total and Investment Revenues Revenues Revenues EBIT Amortization Expenditures ----------------------------------------------------------------------------- Six Months Ended June 30, 2002 Franchised Electric $ 2,275 $ - $ 2,275 $ 774 $ 307 $ 567 Natural Gas Transmission 1,092 70 1,162 580 144 2,273 Field Services 2,834 544 3,378 76 145 184 Duke Energy North America 16,165 70 16,235 250 68 1,521 International Energy 2,173 3 2,176 134 52 217 Other Energy Services 3,529 189 3,718 83 11 22 Duke Ventures 150 - 150 62 9 283 Other Operations \\a\\ - (41) (41) (207) 5 - Eliminations and minority interests - (835) (835) 56 - - ----------------------------------------------------------------------------- Total consolidated $ 28,218 $ - $ 28,218 $ 1,808 $ 741 $ 5,067 - ---------------------------------------------------------------------------------------------------------- Six Months Ended June 30, 2001 Franchised Electric $ 2,311 $ - $ 2,311 $ 821 $ 292 $ 452 Natural Gas Transmission 474 72 546 317 71 286 Field Services 4,871 1,065 5,936 207 138 307 Duke Energy North America 20,828 293 21,121 656 45 1,326 International Energy 896 5 901 144 48 158 Other Energy Services 2,556 221 2,777 (44) 23 47 Duke Ventures 135 - 135 43 9 363 Other Operations \\a\\ - 121 121 (143) 16 59 Eliminations and minority interests - (1,777) (1,777) 155 - - ----------------------------------------------------------------------------- Total consolidated $ 32,071 $ - $ 32,071 $ 2,156 $ 642 $ 2,998 - ----------------------------------------------------------------------------------------------------------
\\a\\ Other operations primarily includes certain unallocated corporate costs. Segment assets in the accompanying table are net of intercompany advances, intercompany notes receivable, intercompany current assets, intercompany derivative assets and investments in subsidiaries. - --------------------------------------------------------------------- Segment Assets (in millions) - --------------------------------------------------------------------- June 30, December 31, 2002 2001 ------------------------- Franchised Electric $13,054 $12,964 Natural Gas Transmission 15,875 5,027 Field Services 6,682 7,113 Duke Energy North America 19,548 14,107 International Energy 5,801 5,115 Other Energy Services 1,022 1,139 Duke Ventures 2,123 1,926 Other Operations, net of eliminations 1,087 984 ------------------------- Total consolidated $65,192 $48,375 - --------------------------------------------------------------------- 17 6. Debt In January 2002, Duke Energy issued $750 million of 6.25% senior unsecured bonds due in 2012 and $250 million of floating rate (based on the three-month London Interbank Offered Rate (LIBOR) plus 0.35%) senior unsecured bonds due in 2005. The proceeds from these issuances were used for general corporate purposes. In February 2002, Duke Capital Corporation, a wholly owned subsidiary of Duke Energy, issued $500 million of 6.25% senior unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due in 2032. In addition, Duke Capital Corporation, through a private placement transaction, issued $500 million of floating rate (based on the one-month LIBOR plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these issuances were used for general corporate purposes. In March 2002, a wholly owned subsidiary of Duke Energy, Duke Australia Pipeline Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with various banks to fund its pipeline and power businesses in Australia. The facility is split between a Duke Capital Corporation-guaranteed tranche and a non-recourse project finance tranche that is secured by liens over existing Australian pipeline assets. Proceeds from the project finance tranche were used to repay inter-company loans. In April 2002, Duke Energy issued $250 million of 6.60% retail bonds due in 2022. The senior unsecured bonds were insured to obtain an `AAA' credit rating. Duke Energy subsequently swapped the bonds to a floating rate (based on the three-month LIBOR). The proceeds from this issuance were used for general corporate purposes. In addition, Duke Capital Corporation, through a private placement transaction, issued $100 million of floating rate (based on the one-month LIBOR plus 0.85%) senior unsecured bonds due in 2004. The proceeds from this issuance were used to repay commercial paper. In July 2002, Texas Eastern Transmission, LP, a wholly owned subsidiary of Duke Energy, issued $300 million of 5.25% senior unsecured bonds due in 2007 and $450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these issuances were used for general corporate purposes, including the repayment of debt which matured in July 2002. On March 14, 2002, Duke Energy acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a wholly owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by Duke Energy. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. (See Note 3.) Duke Energy's debt agreements contain various financial and other covenants. Failure to meet these covenants beyond applicable grace periods could result in the acceleration of due dates of the borrowings and/or termination of the agreements. As of June 30, 2002, Duke Energy is in compliance with these covenants. 7. Commitments and Contingencies Environmental. In June 2002, the state of North Carolina passed new clean air legislation that freezes electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007 (rate freeze period), in order for North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state's coal-fired power plants over the next ten years. Management estimates Duke Energy's cost of achieving the proposed emission reductions to be approximately $1.5 billion. Included in the legislation are provisions that allow electric utilities, including Duke Energy, to accelerate the recovery of these compliance costs by amortizing them over seven years (2003-2009). During the rate freeze period, Duke Energy is expected to recover 70% of the total estimated costs of plant improvements. In years six and seven of the recovery period, the NCUC will determine how any remaining costs will be recovered. 18 Notice of Proposed Rulemaking (NOPR) on Standards of Conduct. In September 2001, the FERC issued a NOPR announcing that it is considering new regulations regarding standards of conduct that would apply uniformly to natural gas pipelines and electric transmitting public utilities that are currently subject to different gas or electric standards. The proposed standards would change how companies and their affiliates interact and share information by broadening the definition of "affiliate" covered by the standards of conduct. The NOPR also seeks comment on whether the standards of conduct should be broadened to include the separation of employees involved in the bundled retail electric sales function from those in the transmission function, as the current standards only require those involved in wholesale sales activities to be separated from the transmission function. Various entities filed comments on the NOPR with the FERC, including Duke Energy which filed in December 2001. In April 2002 the FERC Staff issued an analysis of the comments received by the FERC. In several areas, the staff's analysis reflects important changes to the NOPR. However, with regard to corporate governance, the staff's analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions) and transmission functions within a single company that conducts both electric transmission and marketing functions (such as Duke Power). Duke Energy filed supplemental comments in June 2002. A final rule is expected in the fall of 2002. At its meeting in July 2002, the FERC issued its 600-page Standard Market Design NOPR. The NOPR has major implications for the delivery of electric energy throughout the U.S. Major elements of the FERC proposal include: (a) The use of Network Access Service to replace the existing network and point-to-point services. All customers, including load serving entities on behalf of bundled retail load, would be required to take this service under a new pro forma tariff. There would be no transmission rate pancaking among regions because through-and-out charges would be eliminated. (b) By July 31, 2003, vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems. (c) Congestion management would be provided through the use of Locational Marginal Pricing, a transparent method of pricing transmission congestion costs as a component of energy transactions in a given market. Market participants would be allocated or could purchase Congestion Revenue Rights to manage congestion risk. (d) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. Some of these features are likely to be highly contested by the various stakeholders. Duke Energy has initiated a detailed review of the NOPR. Initial comments on the NOPR are due to the FERC by October 15, 2002. The FERC has indicated that it intends to issue a final rule by February 2003. While the NOPR is complex, and remains under review, the early indications are that it appears unlikely to materially impact the consolidated financial statements of Duke Energy. Litigation and Contingencies. California Matters. Duke Energy, some of its subsidiaries, and three current or former executives have been named as defendants, among numerous other corporate and individual defendants, in one or more of a total of 14 lawsuits, filed in California on behalf of purchasers of electricity in the State of California, with one suit filed on behalf of a Washington State electricity purchaser. Most of these lawsuits seek class action certification and damages, and other relief, as a result of the defendants' alleged unlawful manipulation of the California wholesale electricity markets. These lawsuits generally allege that the defendants manipulated the wholesale electricity markets in violation of state laws against unfair and unlawful business practices and, in some suits, in violation of state antitrust laws. Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained revenues for sales of electricity and, in some lawsuits, an award of treble damages for alleged violations of state antitrust laws. The first six of these lawsuits were filed in late 2000 through mid-2001 and have been consolidated before a single judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master Amended Complaint in March 2002, which adds additional defendants. The claims against the defendants are similar to those in the original complaints. In April 2002, some defendants, including Duke Energy, filed cross-complaints 19 against various market participants not named as defendants in the plaintiffs' original and amended complaints. Eight of these 14 suits were filed in mid-2002, seven by plaintiffs in California and one by a plaintiff in the State of Washington. These eight suits are being considered for consolidation with the six previously filed lawsuits. These matters are in their earliest stages. Duke Energy is currently evaluating these claims and intends to vigorously defend itself. Duke Energy and its subsidiaries are involved in other legal and regulatory proceedings and investigations related to activities in California. These other activities were disclosed in Duke Energy's Form 10-K for the year ended December 31, 2001, and there have been no new material developments in relation to these issues. Trading Matters. Since April 2002, 16 shareholder class action lawsuits have been filed against Duke Energy: 13 in the United States District Court for the Southern District of New York and three in the United States District Court for the Western District of North Carolina. Some of the lawsuits also name as co-defendants some Duke Energy executives, Duke Energy's independent external auditor and various investment banking firms. In addition, Duke Energy has received a shareholder's derivative notice demanding that it commence litigation against named executives and directors of Duke Energy for alleged breaches of fiduciary duties and insider trading. Duke Energy has also received a second similar shareholder's derivative notice demanding litigation against named executives and directors for alleged failure to prevent damages caused to Duke Energy arising from trades involving simultaneous purchases and sales of power and gas at the same price ("round-trip" trading). Duke Energy's response date to the first derivative demand has been extended to after the first of the year 2003. Duke Energy is negotiating a similar agreement with respect to the second derivative demand. The class actions and the threatened shareholder derivative claims arise out of allegations that Duke Energy improperly engaged in the so-called "round trip" trades which resulted in an alleged overstatement of revenues over a three-year period of approximately $1 billion. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys' fees and costs for alleged violations of securities laws. In one of the lawsuits, the plaintiffs assert a common law fraud claim and seek, in addition to compensatory damages, disgorgement and punitive damages. These matters are in their earliest stages. Duke Energy is currently evaluating these claims and intends to vigorously defend itself. In 2002, Duke Energy received and responded to information requests from the FERC, an informal request for information from the Securities and Exchange Commission (SEC), and a subpoena from the Commodity Futures Trading Commission. Duke Energy also received and will respond to a grand jury subpoena issued by the U.S. Attorney's office in Houston. All information requests and subpoenas seek documents and information related to trading activities, including so-called "round-trip" trading. Duke Energy is cooperating with the respective governmental agencies on each of these inquiries. Duke Energy submitted a final report to the SEC based on a review of approximately 750,000 trades made by various Duke Energy subsidiaries between January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review of trading, accounting, and other records, with the assistance of Duke Energy senior legal, corporate risk management and accounting personnel. Duke Energy identified 28 "round-trip" transactions done for the apparent purpose of increasing volumes on the Intercontinental Exchange and 61 "round-trip" transactions done at the direction of one of Duke Energy's traders that did not have a legitimate business purpose and were contrary to corporate policy. Duke Energy determined that the financial impact of these "round trip" transactions was not material. As a result of the trading review, Duke Energy has terminated two employees and put in place additional risk management procedures to improve and strengthen the oversight and controls of its trading operations. Duke Energy has also reconfirmed to employees that engaging in simultaneous or prearranged transactions 20 that lack a legitimate business purpose, or any trading activities that lack a legitimate business purpose, is against company policy. Beginning August 1, 2002, North American trading and marketing functions currently in DENA and DEM, including DETM and the Canadian trading operations, will be consolidated into one group. This organization will develop consistent policies, practices and systems for the entire trading and marketing operation and implement better control systems to improve monitoring and reporting capabilities. Price Mitigation Matters. In November 2001, Nevada Power Company and Sierra Pacific Power Company (collectively, the Companies) filed a complaint with the FERC against DETM. The complaint requests the FERC to mitigate prices in sales contracts between Duke Energy and Nevada Power, and Duke Energy and Sierra Pacific that were entered into between December 7, 2000 and June 20, 2001. The Companies allege that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the California market to be dysfunctional and uncompetitive, and that the California market influenced the contract prices. In April 2002, the FERC issued an order which provides for an evidentiary hearing, establishes refund dates, and requires the parties to participate in settlement negotiations. The parties have reached a settlement pursuant to which the Companies dismissed their complaint against DETM in June 2002. As part of this settlement, Duke Energy has agreed to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to the Companies to fulfill customers' power requirements during the peak summer period. DETM is an intervener in cases against other sellers to these two utilities, but is no longer a respondent in this proceeding. In July 2002, the Sacramento Municipal Utility District (SMUD) filed a complaint with the FERC against DETM requesting that the FERC mitigate unjust and unreasonable prices in four mid- and long-term sales contracts between DETM and SMUD entered into between February 7, 2001 and March 26, 2001. SMUD, alleging that DETM had the ability to exercise market power, claims that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the western markets to be dysfunctional and uncompetitive and that the western markets influenced their price. In support of its request to mitigate the contract price, SMUD relies on the fact that the contract prices are higher than prices in the western U.S. following implementation of the FERC's June 2001 price mitigation plan. SMUD requests the FERC to set "just and reasonable" contract rates and to promptly set a refund effective date. 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 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. Regulatory Matters. North Carolina law requires the Secretary of Revenue to distribute to municipalities a specified portion of the tax revenue derived from electric franchise taxes paid by utilities. However, asserting his constitutional duty to prevent a budget deficit, the Governor issued an Executive Order in February 2001 directing the withholding of distributions to municipalities. In response, several municipalities have passed ordinances to "double tax" Duke Energy's gross receipts effective July 2002. The tax rate is 3.09% on gross receipts and the potential liability, if all municipalities in Duke Energy's service territory passed similar ordinances, is approximately $65 million per year. In July 2002, Duke Energy's request for a hearing before the North Carolina Secretary of Revenue on the new taxes was denied on the grounds that the Secretary has no jurisdiction over tax assessments issued by municipalities. Duke Energy intends to appeal the Secretary's jurisdictional determination to the State Tax Appeal Board. Duke Energy also reserves the option to litigate this issue in state Superior Court. Electric Competition. GridSouth received provisional approval from the FERC in March 2001. However, in July 2001 the FERC ordered GridSouth and other utilities in the Southeast to join in 45 days of 21 mediation to negotiate terms of a Southeast Regional Transmission Organization (RTO). The FERC has not issued an order specifically based on those proceedings. Duke Energy, Carolina Power & Light Company and South Carolina Electric & Gas Company have withdrawn their applications to the PSCSC and NCUC to transfer functional control of their electric transmission assets to GridSouth. Efforts surrounding the further development of GridSouth have been suspended until clarification from the FERC is received on matters such as standard market design, transmission upgrade cost allocation and standards of conduct. In addition, Duke Energy is participating in an RTO cost/benefit study initiated by the Southeastern Association of Regulatory Utility Commissioners. 8. Subsequent Events Westcoast, a wholly owned subsidiary of Duke Energy, has entered into an agreement to sell its 60% interest in the Frederickson Power Project for cash proceeds of approximately $100 million. This transaction is subject to regulatory approvals and is expected to be finalized by the end of the third quarter of 2002. In July 2002, Duke Energy International, LLC, a wholly owned subsidiary of Duke Energy, acquired a 103 megawatt gas-fired combined heat and power plant located in northwest France for approximately $69 million. In July 2002, Standard & Poor's (S&P) placed its ratings for Duke Energy, Duke Capital Corporation and some of its other subsidiaries on CreditWatch with negative implications. Moody's Investors Service and Fitch Ratings changed their ratings outlooks for Duke Energy, Duke Capital Corporation and some of its subsidiaries from Stable to Negative. In August 2002, Duke Energy was informally advised by S&P that its credit ratings described above would be lowered one rating level and S&P would change its negative outlook to stable. Duke Energy was also informally advised that S&P's commercial paper rating would remain at current levels. Duke Energy does not anticipate these actions to have a material adverse impact on its financial results. 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 seven 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 June 30, 2002, earnings available for common stockholders were $470 million, or $0.57 per basic share. For the comparable 2001 period, earnings available for common stockholders were $415 million, or $0.54 per basic share. The increase was due primarily to a 16.1% increase in earnings before interest and taxes (EBIT), as described below. Offsetting the comparative increase in EBIT was a $17 million increase in minority interest expense, as discussed in the following sections, and a $62 million increase in interest expense due primarily to the debt assumed in the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002. (See Note 3 to the Consolidated Financial Statements.) For the six months ended June 30, 2002, earnings available for common stockholders were $849 million, or $1.05 per basic share. For the comparable 2001 period, earnings available for common stockholders were $869 million, or $1.14 per basic share. The decrease was due primarily to a 16.1% decrease in EBIT, as described below, and a $38 million increase in interest expense. These changes were partially offset by the prior year's one-time net-of-tax charge of $96 million, or $0.13 per basic share. This one-time charge was the cumulative effect of change in accounting principle for the January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." Also offsetting the changes in EBIT and interest expense was a $111 million decrease in minority interest expense and a decrease in the effective tax rate, both of which are discussed in the following sections. 22 Operating income increased $108 million to $988 million for the quarter, but decreased $383 million to $1,679 million for the six months ended June 30, 2002. EBIT increased $145 million to $1,047 million for the quarter, but decreased $348 million to $1,808 million for the six months ended June 30, 2002. Operating income and EBIT are affected by the same fluctuations for Duke Energy and each of its business segments. The following table shows the components of EBIT and reconciles EBIT to net income. - -------------------------------------------------------------------------------- Reconciliation of Operating Income to Net Income (in millions) - -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, --------------------------------------- 2002 2001 2002 2001 --------------------------------------- Operating income $ 988 $ 880 $ 1,679 $ 2,062 Other income and expenses 59 22 129 94 -------------------------------------- EBIT 1,047 902 1,808 2,156 Interest expense 264 202 453 415 Minority interest expense 62 45 94 205 -------------------------------------- Earnings before income taxes 721 655 1,261 1,536 Income taxes 247 236 405 563 -------------------------------------- Income before cumulative effect of change in accounting principle 474 419 856 973 Cumulative effect of change in accounting principle, net of tax - - - (96) -------------------------------------- Net income $ 474 $ 419 $ 856 $ 877 - -------------------------------------------------------------------------------- EBIT is the primary performance measure used by management to evaluate segment performance. As an indicator of Duke Energy's operating performance or liquidity, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles. Duke Energy's EBIT may not be comparable to a similarly titled measure of another company. Prior to April 1, 2002, the Duke Energy North America (DENA) business segment was combined with Duke Energy Merchants Holdings, LLC (DEM) to form a segment called North American Wholesale Energy. During 2002, management combined DEM with the Other Energy Services segment. Previous periods have been restated to conform to the current presentation. Beginning August 1, 2002, Duke Energy's North American trading and marketing functions currently in DENA and DEM, including Duke Energy Trading and Marketing. LLC (DETM) and the Canadian trading operations, will be consolidated into one group. Business segment EBIT is summarized in the following table, and detailed discussions follow. - -------------------------------------------------------------------------------- EBIT by Business Segment (in millions) - -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, --------------------------------------- 2002 2001 2002 2001 --------------------------------------- Franchised Electric $ 389 $ 361 $ 774 $ 821 Natural Gas Transmission 312 142 580 317 Field Services 41 84 76 207 Duke Energy North America 196 272 250 656 International Energy 67 68 134 144 Other Energy Services 72 (12) 83 (44) Duke Ventures 56 36 62 43 Other Operations (128) (73) (207) (143) EBIT attributable to minority interests 42 24 56 155 -------------------------------------- Consolidated EBIT $ 1,047 $ 902 $ 1,808 $ 2,156 - -------------------------------------------------------------------------------- 23 Other Operations primarily includes certain unallocated corporate costs and elimination of intersegment profits. The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements. Franchised Electric - -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------ (in millions, except where noted) 2002 2001 2002 2001 - -------------------------------------------------------------------------------- Operating revenues $ 1,162 $ 1,154 $ 2,275 $ 2,311 Operating expenses 790 779 1,536 1,527 ------------------------------------------ Operating income 372 375 739 784 Other income (loss), net of expenses 17 (14) 35 37 ------------------------------------------ EBIT $ 389 $ 361 $ 774 $ 821 ========================================== Sales, GWha 20,418 20,221 39,939 39,583 - -------------------------------------------------------------------------------- \\a\\ Gigawatt-hours Franchised Electric's EBIT increased $28 million for the quarter as compared to the same period in 2001. The increase was due primarily to lower operating and maintenance expenses, primarily resulting from fewer nuclear plant outages for repairs and maintenance in the second quarter of 2002, and increased residential and general service sales, due to warmer weather in the second quarter of 2002 and continued growth in the average number of customers in Franchised Electric's service territory. These increases to EBIT were partially offset by lower sales in the industrial class, due to the slowing economy. For the six months ended June 30, 2002, EBIT for Franchised Electric decreased $47 million as compared to the same period in 2001. The decrease was due primarily to $33 million in mutual insurance distributions recorded as income in the first quarter of 2001 and the favorable settlement of forward power sales contracts used to manage price risk for Franchised Electric's wholesale market-rate sales in the first quarter of 2001. Since the third quarter of 2001, the mutual insurance distributions have been reclassified from earnings to a deferred credit account as required by the North Carolina Utilities Commission (NCUC), pending final outcome of a regulatory audit which will likely determine the treatment of those distributions. Earnings also decreased as a result of lower sales in the industrial class, due to the slowing economy. These decreases in earnings were partially offset by lower operating and maintenance expenses, primarily resulting from fewer nuclear plant outages for repairs and maintenance in 2002 and by continued growth in the average number of customers in Franchised Electric's service territory. The following table shows the changes in GWh sales and average number of customers. - -------------------------------------------------------------------------------- Increase (decrease) over prior year Three Months Ended Six Months Ended - -------------------------------------------------------------------------------- Residential sales 4.0% (1.7)% General service sales 2.8% 1.1% Industrial sales (2.8)% (6.1)% Total Franchised Electric sales 1.0% 0.9% Average number of customers 2.6% 1.4% - ------------------------------------------------------------------------------- In June 2002, the state of North Carolina passed new clean air legislation that freezes electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007, in order for North Carolina electric utilities to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state's coal-fired power plants. (See Current Issues - Environmental for additional information.) As part of this legislation, Duke Energy will spend an estimated $1.5 billion to modify its coal-fired plants. Included in the legislation are provisions that allow electric utilities, including Duke Energy, to accelerate the recovery of these compliance costs by amortizing them over seven years. While the increased amortization expense will lower Franchised Electric's earnings beginning in 2003, the rate freeze reduces uncertainty over the next five years. 24 Natural Gas Transmission - -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ------------------------------------- (in millions, except where noted) 2002 2001 2002 2001 - -------------------------------------------------------------------------------- Operating revenues $ 678 $ 264 $1,162 $ 546 Operating expenses 361 125 579 232 ------------------------------------- Operating income 317 139 583 314 Other income, net of expenses 4 3 9 3 Minority interest expense 9 - 12 - ------------------------------------- EBIT $ 312 $ 142 $ 580 $ 317 ===================================== Proportional throughput, TBtu a 702 368 1,372 916 - -------------------------------------------------------------------------------- a Trillion British thermal units For the quarter ended June 30, 2002, EBIT for Natural Gas Transmission increased $170 million, and for the six months, EBIT increased $263 million compared to the same periods in 2001. The increase for both periods primarily resulted from earnings from the natural gas transmission and distribution assets acquired as a part of the acquisition of Westcoast in March 2002. (See Note 3 to the Consolidated Financial Statements.) Earnings for Westcoast were $109 million for the quarter and $172 million for the six months. Earnings associated with market expansion projects, including the Gulfstream Natural Gas System, a 581-mile pipeline system, 50% owned by Duke Energy that went into service in May 2002, also contributed to both periods. These earnings included a $27 million construction fee from an affiliate related to the successful completion of the Gulfstream Natural Gas System. Also contributing to the six-month period was a $14 million gain on the sale of a portion of Natural Gas Transmission's limited partnership interest in Northern Border Partners, LP, which owns a general partnership interest in Northern Border Pipeline Company. 25 Field Services - -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ----------------------------------------- (in millions, except where noted) 2002 2001 2002 2001 - -------------------------------------------------------------------------------- Operating revenues $ 1,812 $ 2,538 $ 3,378 $ 5,936 Operating expenses 1,758 2,406 3,281 5,625 ---------------------------------------- Operating income 54 132 97 311 Minority interest expense 13 48 21 104 ---------------------------------------- EBIT $ 41 $ 84 $ 76 $ 207 ======================================== Natural gas gathered and processed/transported, TBtu/d a 8.4 8.5 8.4 8.4 Natural gas liquid (NGL) production, MBbl/d b 392.0 406.7 390.4 386.9 Natural gas marketed, TBtu/d 1.6 1.6 1.6 1.6 Average natural gas price per MMBtu c $ 3.40 $ 4.67 $ 2.86 $ 5.88 Average NGL price per gallon d $ 0.37 $ 0.48 $ 0.34 $ 0.54 - -------------------------------------------------------------------------------- a Trillion British thermal units per day b Thousand barrels per day c Million British thermal units d Does not reflect results of commodity hedges EBIT for Field Services decreased $43 million for the quarter and $131 million for the six months ended June 30, 2002 compared to the same periods in 2001, due primarily to increases in operating and maintenance costs and decreases in commodity prices. The decrease in commodity prices was driven by decreases in average NGL prices of $0.11 per gallon for the quarter and $0.20 per gallon for the six months, partially offset by decreases in the average natural gas prices of $1.27 per MMBtu for the quarter and $3.02 per MMBtu for the six months. During the quarter, Field Services also recorded charges for an increase in its provision for imbalances with customers and suppliers and a reduction to its storage inventory resulting from a study completed on one of Field Services' sites to determine the current capacity levels. The net EBIT impact, after minority interest, of these charges was $13 million. Subsequent to earnings being reported to Duke Energy for the quarter ended June 30, 2002, Field Services determined and recorded various adjustments which reduced reported EBIT for June 2002 based on new information and analysis. These adjustments are not material to the results of Duke Energy and they are not reflected in Duke Energy's second quarter 2002 financial statements. 26 Duke Energy North America
- ------------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------- (in millions, except where noted) 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------ Operating revenues $ 9,443 $ 10,051 $ 16,235 $ 21,121 Operating expenses 9,237 9,824 15,975 20,431 ------------------------------------------------------- Operating income 206 227 260 690 Other income, net of expenses 4 15 3 4 Minority interest expense (benefit) 14 (30) 13 38 ------------------------------------------------------- EBIT $ 196 $ 272 $ 250 $ 656 ======================================================= Natural gas marketed, TBtu/d 18.8 11.2 18.1 12.3 Electricity marketed and traded, GWh 95,385 66,225 201,601 110,842 Proportional megawatt capacity in operation 12,671 6,846 Proportional megawatt capacity owned\\a\\ 18,671 13,231 - ------------------------------------------------------------------------------------------------------
\\a\\ Includes under construction or under contract at period end For the quarter ended June 30, 2002, DENA's EBIT decreased $76 million and for the six months, it decreased $406 million, as compared to the same periods in 2001. An increase of 85.1% in the proportional megawatt capacity of generation assets in operation and increases in the marketing and trading of electricity volumes of 44.0% for the quarter and 81.9% for the six months were significantly offset by decreased origination activities and trading margins. Last year's results were driven by unusually high natural gas and power prices, and volatility levels (measures of the fluctuation in the prices of energy contracts), especially in the western U.S. The second quarter of 2001 also included significant net gains from the sale of interests in generating facilities as a result of DENA executing its portfolio management strategy. Partially offsetting these decreases were lower variable compensation costs related to the trading activities. Results for the second quarter of 2002 also include a $46 million appreciation of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques for all North American regions. As a result of Duke Energy's findings related to the Securities and Exchange Commission's (SEC) informal inquiry on electricity trades involving simultaneous purchases and sales of power at the same price ("round trip" trades), DENA recorded adjustments which reduced its EBIT by $17 million during the quarter ended June 30, 2002. An additional $2 million charge was recorded in other Duke Energy business segments related to these findings. (See Current Issues- Litigation and Contingencies, Trading Matters for additional information.) For the prior year quarter, losses at DETM resulted in a minority interest benefit, whereas increased earnings at DETM for the current year quarter resulted in minority interest expense. When compared to the prior year, minority interest expense for the six months decreased $25 million due to changes in the ownership percentage of DENA's waste-to-energy plants and decreased earnings at DETM. In June 2002, the Financial Accounting Standards Board's (FASB) Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and EITF No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods must be reclassified to reflect presentation on a net basis. Also, 27 companies must disclose volumes of physically settled energy trading contracts. Duke Energy is evaluating the impact of this new consensus on the presentation of its Consolidated Statement of Income, but believes it will have a material impact on total revenues and expenses. The partial consensus will have no impact on net income. International Energy
- ------------------------------------------------------------------------------------------------------ Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------ (in millions, except where noted) 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------ Operating revenues $ 1,190 $ 399 $ 2,176 $ 901 Operating expenses 1,125 334 2,052 762 ------------------------------------------------------ Operating income 65 65 124 139 Other income, net of expenses 8 9 21 18 Minority interest expense 6 6 11 13 ------------------------------------------------------ EBIT $ 67 $ 68 $ 134 $ 144 ====================================================== Sales, GWh\\a\\ 5,014 4,596 9,946 9,037 Natural gas marketed, TBtu/d 3.7 2.5 3.4 2.4 Electricity marketed and traded, GWh 24,740 1,632 41,872 3,391 Proportional megawatt capacity in operation 4,971 4,241 Proportional megawatt capacity owned \\b\\ 5,746 4,844 Proportional maximum pipeline capacity in operation \\b\\, MMcf/d c 363 255 Proportional maximum pipeline capacity owned \\b\\, MMcf/d 363 363 - ------------------------------------------------------------------------------------------------------
\\a\\ GWh sold by the operating assets to consumers, industrial users, etc. \\b\\ Includes under construction or under contract at period end \\c\\ Million cubic feet per day International Energy's EBIT decreased $1 million for the quarter and $10 million for the six months ended June 30, 2002 compared to the same periods in 2001. The decreases were due primarily to decreased earnings from the European operations, which were affected by lower trading margins and lower product prices. Partially offsetting the decrease from the European operations, were increased earnings from the Latin American and Asia Pacific operations, which included additions to International Energy's portfolio of assets from Duke Energy's acquisition of Westcoast. The increases in International Energy's operating revenues and expenses for 2002 are due primarily to its increased trading and marketing activities in Europe. Other Energy Services
- ------------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------- (in millions) 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------- Operating revenues $ 2,388 $ 1,591 $ 3,718 $ 2,777 Operating expenses 2,333 1,606 3,652 2,826 ------------------------------------------------------- Operating income 55 (15) 66 (49) Other income, net of expenses 17 3 17 5 ------------------------------------------------------- EBIT $ 72 $ (12) $ 83 $ (44) - -------------------------------------------------------------------------------------------------------
28 For the quarter ended June 30, 2002, EBIT for Other Energy Services increased $84 million and for the six months, it increased $127 million, compared to the same periods in 2001. The increases for the quarter and six months were due primarily to increased earnings at Duke/Fluor Daniel (D/FD), as a result of D/FD completing a number of energy plants. Most of the plants completed during the quarter were constructed for DENA and therefore the related intercompany profit has been eliminated within the Other Operations segment. Increased earnings at DEM also contributed to the quarter and the six months, primarily due to a prior year $57 million Agrifos reserve for bankruptcy and a current year gain of $15 million on the sale of DEM's remaining interest in Canadian 88. On April 30, 2002, Duke Energy completed the sale of Duke Engineering & Services, Inc. to Framatome ANP, Inc. and, on May 1, 2002, Duke Energy completed the sale of DukeSolutions, Inc. to Ameresco, Inc. (See Note 3 to the Consolidated Financial Statements). The combined result of these sales was a net gain of $14 million for the quarter and a net loss of $1 million for the six months. The difference between the quarterly and the six month results is due to a $15 million reserve that was established in the first quarter of 2002 for the expected loss associated with the sale of DukeSolutions, Inc. Duke Ventures
- --------------------------------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, --------------------------------------------------------- (in millions) 2002 2001 2002 2001 - --------------------------------------------------------------------------------------------------------- Operating revenues $ 111 $98 $ 150 $135 Operating expenses 55 62 89 92 --------------------------------------------------------- Operating income 56 36 61 43 Minority interest benefit - - (1) - --------------------------------------------------------- EBIT $ 56 $36 $ 62 $ 43 - ---------------------------------------------------------------------------------------------------------
EBIT for Duke Ventures increased $20 million for the quarter and $19 million for the six months ended June 30, 2002 compared to the same periods in 2001, due primarily to a gain of approximately $30 million on the sale of Duke Energy's remaining water operations during the second quarter of 2002. Partially offsetting this gain were decreased earnings at Crescent Resources, LLC, due primarily to decreased commercial project sales and rents. Other Operations For the quarter ended June 30, 2002, Other Operations' EBIT decreased $55 million and for the six months, it decreased $64 million, compared to the same periods in 2001. The decreases are due primarily to increased intercompany profits between Duke Energy's segments which are eliminated within the Other Operations Segment. These intercompany profits include earnings at D/FD for energy plants it has completed for DENA. Other Impacts on Earnings Available for Common Stockholders For the quarter ended June 30, 2002, interest expense increased $62 million and for the six months ended June 30, 2002, interest expense increased $38 million compared to the same periods in 2001. The increases are primarily due to higher debt balances resulting from debt assumed in the acquisition of Westcoast. Minority interest expense increased $17 million for the quarter but decreased $111 million for the six months ended June 30, 2002 compared to the same periods in 2001. Minority interest expense includes expense related to regular distributions on preferred securities of Duke Energy and its subsidiaries. This expense decreased $6 million for the quarter and $17 million for the six months ended June 30, 2002 due primarily to lower distributions related to Catawba River Associates, LLC (Catawba). Catawba is a fully consolidated financing entity formed by Duke Energy in September 2000 and is managed by a Duke Energy subsidiary. 29 Minority interest expense as shown and discussed in the preceding business segment EBIT discussions 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) increased $23 million for the quarter but decreased $94 million for the six month period. For the quarter, the change was driven by increased income at DETM, DENA's joint venture with Exxon Mobil Corporation, partially offset by decreased income from Duke Energy's joint venture with Phillips Petroleum. For the six months, the change was driven by decreased income from Field Services joint venture, changes in the ownership percentage of DENA's waste-to-energy plants and decreased earnings at DETM. A state tax settlement finalized during the first quarter of 2002, as well as a benefit from a change in tax law, resulted in an effective tax rate of 32% for the six month period, compared to 37% for the same period in 2001. Duke Energy's annual effective tax rate for 2002 is expected to be in the range of 35%-36%. During the first quarter of 2001, Duke Energy recorded a one time net-of-tax charge of $96 million related to the cumulative effect of change in accounting principle for the January 1, 2001 adoption of SFAS No. 133. This charge related to contracts that either did not meet the definition of a derivative under previous accounting guidance or do not qualify as hedges under new accounting requirements. LIQUIDITY AND CAPITAL RESOURCES Operating Cash Flows For the six months ended June 30, 2002, net cash provided by operations decreased $665 million when compared to the same period in 2001. The decrease is due primarily to cash posted by counterparties. Counterparties may be required to post collateral in cash or letters of credit if price moves benefit Duke Energy. This mechanism gives Duke Energy use of those funds on a short-term basis. Conversely, negative price impacts reduce earnings and may require Duke Energy to post collateral with its counterparties. Cash collateral posted by Duke Energy is included in Other Current Assets and cash collateral collected by Duke Energy is included in Other Current Liabilities on the Consolidated Balance Sheets. In 2002, Duke Energy held less cash posted by counterparties (primarily due to cash posted by Enron Corporation in 2001). In addition, during the first six months of 2001, Duke Energy reduced the amount of cash it had posted with counterparties from December 31, 2000. Partially offsetting these reductions were increased amounts of net payables related to higher gas prices and contract volumes and the net unrealized mark-to-market and hedging transactions resulting from increased cash earnings in 2002 versus 2001. As a result of the increased volatility and higher prices in the western U.S. for power in 2001, Duke Energy experienced a higher level of mark-to-market appreciation as compared to 2002. Investing Cash Flows Net cash used in investing activities increased $2,374 million for the six months ended June 30, 2002 when compared to the same period in 2001, primarily due to the acquisition of Westcoast for $1,690 million in cash, net of cash acquired (see Note 3 to the Consolidated Financial Statements). Capital and investment expenditures increased $307 million in 2002 compared to 2001. The increase reflects additional expansion and development expenditures (especially related to DENA's generating facilities), refurbishment and upgrades to existing assets and minor acquisitions of businesses and assets. Capital spending for 2002 is expected to be approximately $6,800 million, excluding the acquisition of Westcoast. For 2003 and 2004, Duke Energy estimates capital spending to be approximately $4 billion to $6 billion. 30 Financing Cash Flows Duke Energy's consolidated capital structure as of June 30, 2002, including short-term debt, was 53% debt, 36% common equity, 7% minority interests, 3% trust preferred securities and 1% preferred stock. Fixed charges coverage, calculated using the SEC guidelines, was 2.7 times for the six months ended June 30, 2002 and 3.6 times for the six months ended June 30, 2001. The decrease in the fixed charges coverage is attributed primarily to decreased pretax income. Duke Energy's future cash requirements are expected to be funded largely by cash from operations, including the sale of assets. In addition, Duke Energy expects to access the capital markets as needed. Ability to access the capital markets is dependent upon market opportunities presented. Management believes Duke Energy has adequate financial flexibility and resources to meet its future needs. In January 2002, Duke Energy issued $750 million of 6.25% senior unsecured bonds due in 2012 and $250 million of floating rate (based on the three-month London Interbank Offered Rate (LIBOR) plus 0.35%) senior unsecured bonds due in 2005. The proceeds from these issuances were used for general corporate purposes. In February 2002, Duke Capital Corporation, a wholly owned subsidiary of Duke Energy, issued $500 million of 6.25% senior unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due in 2032. In addition, Duke Capital Corporation, through a private placement transaction, issued $500 million of floating rate (based on the one-month LIBOR plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these issuances were used for general corporate purposes. In March 2002, a wholly owned subsidiary of Duke Energy, Duke Australia Pipeline Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with various banks to fund its pipeline and power businesses in Australia. The facility is split between a Duke Capital Corporation-guaranteed tranche and a non-recourse project finance tranche that is secured by liens over existing Australian pipeline assets. Proceeds from the project finance tranche were used to repay inter-company loans. In April 2002, Duke Energy issued $250 million of 6.6% retail bonds due in 2022. The senior unsecured bonds were insured to obtain an `AAA' credit rating. Duke Energy subsequently swapped the bonds to a floating rate (based on the three-month LIBOR). The proceeds from this issuance were used for general corporate purposes. In addition, Duke Capital Corporation, through a private placement transaction, issued $100 million of floating rate (based on the one-month LIBOR plus 0.85%) senior unsecured bonds due in 2004. The proceeds from this issuance were used to repay commercial paper. In July 2002, Texas Eastern Transmission, LP, a wholly owned subsidiary of Duke Energy, issued $300 million of 5.25% senior unsecured bonds due in 2007 and $450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these issuances were used for general corporate purposes, including the repayment of debt which matured in July 2002. On March 14, 2002, Duke Energy acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas Limited (a wholly-owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by Duke Energy. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. In addition to the debt assumed, Westcoast and Union Gas Limited have operating credit facilities of 600 million Canadian dollars and 715 million Canadian dollars, respectively. Borrowings under each of these facilities are subject to and dependent upon the senior unsecured ratings of Westcoast (currently rated A (low) for Dominion Bond Rating Service (DBRS) and A+ for Standard & Poor's) and Union Gas Limited (currently rated A for DBRS and A+ for Standard & Poor's). For the Westcoast credit facility, no material adverse change can be declared if Westcoast maintains a rating of BBB(low) or greater at DBRS or a BBB- or greater at Standard & Poor's. For Union Gas Limited's facility, no material adverse change can be declared if Union Gas Limited maintains a rating of BBB or greater by either DBRS or Standard & Poor's. For both facilities, any outstanding debt would not become due and payable as a result of a change in ratings. 31 Westcoast, headquartered in Vancouver, British Columbia, is a North American energy company with interests in natural gas gathering, processing, transmission, storage and distribution, as well as power generation and international energy businesses. In the transaction, a Duke Energy subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock), and approximately $1.8 billion in cash. Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities in November 2001 along with incremental commercial paper. Duke Energy plans to retire the commercial paper later in 2002 and replace it with permanent capital in the form of equity or equity linked securities. The timing for the equity or equity linked securities will be dependent on the market opportunities presented. The Westcoast acquisition was accounted for using the purchase method of accounting, and goodwill totaling approximately $2.5 billion was recorded in the transaction. Under its commercial paper and extendible commercial notes (ECNs) programs, Duke Energy had the ability, subject to market conditions, to borrow up to $7,098 million as of June 30, 2002 compared with $5,358 million as of December 31, 2001. These programs do not have termination dates. The following table summarizes the commercial paper and ECN capacity as of June 30, 2002.
- ------------------------------------------------------------------------------------------------------------ (in millions) Duke Duke Duke Capital Duke Energy Energy Energy Corporation\\a\\ Field Services International Westcoast Total - ------------------------------------------------------------------------------------------------------------ Commercial Paper $1,250 $2,550 $650 $282 $866 \\b\\ $5,598 ECNs 500 1,000 - - - 1,500 ---------------------------------------------------------------------------------------- Total $1,750 $3,550 $650 $282 $866 $7,098 - ------------------------------------------------------------------------------------------------------------
\\a\\ Duke Capital Corporation provides financing and credit enhancement services for its subsidiaries. \\b\\ As of July 19, 2002, the Union Gas Limited commercial paper program was renegotiated from $471 million to $395 million. The total amount of Duke Energy's bank credit facilities was $6,389 million as of June 30, 2002 compared with $4,606 million as of December 31, 2001. Some of the credit facilities support the issuance of commercial paper and as a result, the issuance of commercial paper reduces the amount available under these credit facilities. As of June 30, 2002, $4,091 million was outstanding in the form of commercial paper and ECNs, and $44 million of borrowings were outstanding under the bank credit facilities. The credit facilities expire from August 2002 to 2005 and are not subject to minimum cash requirements. As of June 30, 2002, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $1,750 million in gross proceeds from debt and other securities. Subsequent to June 30, 2002, these shelf registrations have been reduced by $750 million for the senior unsecured bonds issued in July 2002 by Texas Eastern Transmission, LP. In addition, Westcoast and its subsidiaries had $626 million of unused Canadian debt capacity. In July 2002, Standard & Poor's (S&P) placed its ratings for Duke Energy, Duke Capital Corporation and some of its other subsidiaries on CreditWatch with negative implications. Moody's Investors Service and Fitch Ratings changed their ratings outlooks for Duke Energy, Duke Capital Corporation and some of its subsidiaries from Stable to Negative. In August 2002, Duke Energy was informally advised by S&P that its credit ratings described above would be lowered one rating level and S&P would change its negative outlook to stable. Duke Energy was also informally advised that S&P's commercial paper ratings would remain at current levels. Duke Energy does not anticipate these actions to have a material adverse impact on its financial results. 32 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Risk and Accounting Policies Duke Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy's Policy Committee is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Policy Committee is composed of senior executives who receive periodic updates from the Chief Risk Officer (CRO) on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Mark-to-Market Accounting (MTM accounting). Under the MTM accounting method, an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in earnings during the current period. This accounting method has been used by other industries for many years, and in 1998 the EITF issued guidance that required MTM accounting for energy trading contracts. MTM accounting reports contracts at their "fair value," (the value a willing third party would pay for the particular contract at the time a valuation is made). When available, quoted market prices are used to record a contract's fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract's duration, holders of these contracts must calculate fair value using pricing models or matrix pricing based on contracts with similar terms and risks. This is validated by an internal group independent of Duke Energy's trading area. Holders of thinly traded securities or investments (mutual funds, for example) use similar techniques to price such holdings. Correlation and volatility are two significant factors used in the computation of fair values. Duke Energy validates its internally developed fair values by comparing locations/durations that are highly correlated, using market intelligence and mathematical extrapolation techniques. While Duke Energy uses industry best practices to develop its pricing models, changes in Duke Energy's pricing methodologies or the underlying assumptions could result in significantly different fair values, income recognition and realization in future periods. Hedge Accounting. Hedging typically refers to the mechanism that Duke Energy uses to mitigate the impact of volatility associated with price fluctuations. Hedge accounting treatment is used when Duke Energy contracts to buy or sell a commodity such as natural gas or electricity at a fixed price for future delivery corresponding with anticipated physical sales or purchases of natural gas and power (cash flow hedge). In addition, hedge accounting treatment is used when Duke Energy holds firm commitments or asset positions, and enters into transactions that "hedge" the risk that the price of natural gas or power may change between the contract's inception and the physical delivery date of the commodity ultimately affecting the underlying value of the firm commitment or position (fair value hedge). The majority of Duke Energy's hedging transactions are used to protect the value of future cash flows related to its physical assets. To the extent the hedge is effective, Duke Energy recognizes in earnings the value of the contract when the commodity is purchased or sold, or the hedged transaction occurs or settles. Normal Purchases and Normal Sales, Special Exemption. A unique characteristic of the electric power industry is that electricity cannot be readily stored in significant quantities. As a result, some of the contracts to buy and sell electricity allow the buyer some flexibility in determining when to take electricity and in what quantity to match fluctuating demand. These contracts would normally meet the definition of a derivative requiring MTM or hedge accounting. However, because electricity cannot be readily stored in significant quantities and an entity engaged in selling electricity is obligated to maintain sufficient capacity to meet the electricity needs of its customer base, some electricity contracts with optionality features may qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and Derivative Implementation Group (DIG) Issue No. C15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity." Therefore, contracts that Duke Energy holds for the sale of power in future periods that meet the criteria in DIG Issue No. C15 have been designated as "normal purchases, normal sales" contracts, and are exempted from recognition in the Consolidated Financial Statements until power is delivered. Duke Energy tracks these contracts separately in its hedge portfolio, but no value for these contracts is included in the Consolidated Financial Statements until power is actually delivered. 33 North American Merchant Generation Duke Energy's wholesale energy portfolio in North America includes the merchant generation facilities and trading contracts held for power, natural gas, crude oil and petroleum products. The merchant generation facilities portion of the wholesale energy portfolio is anticipated to be realized in future periods as the generation facilities are dispatched. This future value includes hedge contracts and contracts designated as normal purchases and normal sales. Only the contracts designated and effective as qualifying hedges are reflected on Duke Energy's Consolidated Balance Sheets at fair value. Changes in the fair value of qualifying hedging contracts do not affect current-period earnings. Normal purchases and normal sales contracts are not subject to accounting recognition until contract performance occurs. The remaining portion of the total estimated value of the wholesale energy portfolio is attributed to the current value of trading contracts. These contracts are subject to MTM accounting and changes in the contract fair value are recorded as part of current-period earnings. The following table shows when the expected discounted value of Duke Energy's North American merchant generation facilities portion of the portfolio will be realized in future periods. The table reflects the estimated value of Duke's ability to manage its power plants as options to convert natural gas into power. The estimate is derived from the current forward market prices of fuels and power, less variable plant operating expenses through June 30, 2011 only and not for the life of the asset portfolio. It includes the value associated with hedge transactions and contracts designated as normal purchases and normal sales, but it does not include the value of any mark-to-market trading positions or hedges. Fixed operating costs, overhead, depreciation, taxes, reserves and future capital expenditures are excluded, and the value presented is not intended to reflect fair market value of the portfolio.
- ---------------------------------------------------------------------------------------------------- North American Merchant Generation Portfolio Value as of June 30, 2002 (in millions) - ---------------------------------------------------------------------------------------------------- Maturity in 2005 Total Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter \\a\\ Portfolio Value - ---------------------------------------------------------------------------------------------------- $553 $695 $764 $4,389 $6,401 - ----------------------------------------------------------------------------------------------------
\\a\\ For purposes of calculating total portfolio value, model valuations were calculated through June 2011. Commodity Price Risk Duke Energy, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options for trading purposes and for activity other than trading activity (primarily hedge strategies). (See Notes 2 and 4 to the Consolidated Financial Statements.) Trading. The risk in the trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio (which includes all trading contracts not designated as hedge positions) on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits. DER computations are based on historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days). The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Energy's DER amounts for instruments held for trading purposes are shown in the following table. 34
- ------------------------------------------------------------------------------------------------------------------------------ Daily Earnings at Risk (in millions) - ------------------------------------------------------------------------------------------------------------------------------ Estimated Average Estimated Average High One-Day Low One-Day One-Day Impact on One-Day Impact on Impact on EBIT for Impact on EBIT for EBIT for the three EBIT for three months three months ended three months ended ended June 30, 2002 \\a\\ ended June 30, 2001 \\a\\ June 30, 2002 \\a\\ June 30, 2002 \\a\\ - ------------------------------------------------------------------------------------------------------------------------------ Calculated DER $15 $27 $24 $9 - ------------------------------------------------------------------------------------------------------------------------------
\\a\\ Amount does not include the impact of Westcoast's trading activity. DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk. Duke Energy's exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of Duke Energy's trading instruments during the three months ended June 30, 2002.
- -------------------------------------------------------------------------------------------------- Changes in Fair Value of Trading Contracts (in millions) - -------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at the beginning of the period $1,019 Contracts realized or otherwise settled during the period 186 Fair value of contracts entered into during the period 53 Changes in fair value amounts attributable to changes in valuation techniques \\a\\ 45 Other changes in fair values (108) -------------- Fair value of contracts outstanding at the end of the period $1,195 - ---------------------------------------------------------------------------------------------------
\\a\\ Amount represents appreciation of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques. For the three months ended June 30, 2002, the unrealized net gain recognized in operating income was $103 million, compared to a $68 million loss for the three months ended March 31, 2002. The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values. When available, Duke Energy uses observable market prices for valuing its trading instruments. When quoted market prices are not available, management uses established guidelines for the valuation of these contracts. Management may use a variety of reasonable methods to assist in determining the valuation of a trading instrument, including analogy to reliable quotations of similar trading instruments, pricing models, matrix pricing and other formula-based pricing methods. These methodologies incorporate factors for which published market data may be available. All valuation methods employed by Duke Energy are approved by an independent internal corporate risk management organization. 35 The following table shows the fair value of Duke Energy's trading portfolio as of June 30, 2002. - -------------------------------------------------------------------------------- Fair Value of Trading Contracts as of June 30, 2002 (in millions) - --------------------------------------------------------------------------------
Maturity in Maturity in Maturity in Maturity in 2005 and Total Fair Sources of Fair Value 2002 2003 2004 Thereafter Value - ------------------------------------------------------------------------------------------------------------- Prices supported by quoted market prices and other external sources $217 $185 $114 $ 43 $ 559 Prices based on models and other valuation methods 43 36 69 488 636 - ------------------------------------------------------------------------------------------------------------- Total $260 $221 $183 $531 $1,195 - -------------------------------------------------------------------------------------------------------------
The "prices supported by quoted market prices and other external sources" category includes Duke Energy's New York Mercantile Exchange (NYMEX) futures positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes Duke Energy's forward positions and options in natural gas and power and natural gas basis swaps at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for natural gas and power forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas and power options extend 12 months into the future, on average. Duke Energy values these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes. This category also includes "strip" transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate. The "prices based on models and other valuation methods" category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. It is important to understand that in certain instances structured transactions can be decomposed and modeled by Duke Energy as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different fromthe valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions. Duke Energy's trading portfolio valuation adjustments for liquidity, credit and cost of service are reflected in the above amounts. Hedging Strategies. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of energy commodities related to their power generating and natural gas gathering, processing and marketing activities. Duke Energy closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL contracts to hedge the value of its assets and operations from such price risks. In accordance with SFAS No. 133, Duke Energy's primary use of energy commodity derivatives is to hedge the output and production of assets it physically owns. Contract terms are up to 30 years. These contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by Duke Energy to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in Other Comprehensive Income (OCI) for cash flow hedges and included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 2 and 4 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. 36 Power Price Exposure. As of June 30, 2002, DENA's expected economic output of the merchant generation facilities was 72%, 56% and 55% hedged for 2003, 2004 and 2005, respectively, with respect to its exposure to power prices. These percentages hedged do not refer to the maximum capacity of the facilities. DENA's expected economic output is determined based on current forward spark spreads, current market volatilities for gas and power, the correlation between gas and power and variable operating expenses. The expected economic output will change as market conditions change. The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, as mentioned previously, the gains and losses for these contracts are not recognized in earnings until settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. The fair value of Duke Energy's qualifying hedge positions at a point in time is not necessarily indicative of the value realized when such contracts settle. - -------------------------------------------------------------------------------- Fair Value of Hedge Position Contracts as of June 30, 2002 (in millions) /a/ - --------------------------------------------------------------------------------
Maturity in 2005 Total Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter Contract Value - ----------------------- --------------------- -------------------- --------------------- -------------------- $215 $154 $139 $233 $741 - ----------------------- --------------------- -------------------- --------------------- --------------------
/a/ Includes foreign currency and interest rate hedges that net to approximately a $4 million loss In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward agreements to sell power, bear the same counterparty credit risk as the hedge contracts described above. Under the same risk reduction guidelines used for other contracts, normal purchases and sales contracts are also subject to collateral requirements. Income recognition and realization related to these contracts coincide with the physical delivery of power. Credit Risk Duke Energy's principal customers for power and natural gas marketing services are industrial end-users, marketers and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers throughout these regions. These concentrations of customers may affect Duke Energy's overall credit risk in that some customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, Duke Energy analyzes the counterparties' financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. Duke Energy frequently uses master collateral agreements to mitigate credit exposure. The collateral agreement provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. 37 Despite the current challenges in the energy sector, management believes that the credit risk management process described above is operating effectively. As of June 30, 2002, Duke Energy held cash or letters of credit of $932 million to secure such future performance, and had deposited with counterparties $161 million of such collateral to secure its obligations to provide such future services. Collateral amounts held or posted vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. Duke Energy's and its counterparties' publicly disclosed credit ratings impact the amounts of additional collateral to be posted. The change in market value of NYMEX-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of Duke Energy's counterparties. As of June 30, 2002, Duke Energy had a pre-tax bad debt provision of $90 million related to receivables for energy sales in California. Following the bankruptcy of Enron Corporation, Duke Energy terminated substantially all contracts with Enron Corporation and its affiliated companies (collectively, Enron). As a result, in 2001 Duke Energy recorded, as a charge, a non-collateralized accounting exposure of $43 million. The $43 million non-collateralized accounting exposure was composed of charges of $24 million at Other Energy Services, $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment's earnings in 2001. Duke Energy's determination of its bankruptcy claims against Enron is still under review, and its claims made in the bankruptcy case are likely to exceed $43 million. Any bankruptcy claims that exceed this amount would primarily relate to termination and settlement rights under contracts and transactions with Enron that would have been recognized in future periods, and not in the historical periods covered by the financial statements to which the $43 million charge relates. Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. Duke Energy has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Duke Energy affiliate, Companhia de Geracao de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by Duke Energy's predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Duke Energy affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Duke Energy affiliate to provide liquefied natural gas to Citrus. Citrus has provided a letter of credit in favor of Duke Energy to cover its exposure. Interest Rate Risk Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt, fixed-to-floating interest rate swaps, commercial paper and auction rate preferred stock. Duke Energy manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, options, swaptions and lock agreements to manage and mitigate interest rate risk exposure.(See Notes 2, 4, and 6 to the Consolidated Financial Statements.) 38 Equity Price Risk Duke Energy maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning. As of December 31, 2001 and 2000, these funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents. Duke Energy has an agreement with the NRC that these funds will only be used for activities relating to nuclear decommissioning. Because the accounting for nuclear decommissioning recognizes that costs are recovered through Franchised Electric's rates, fluctuations in equity prices or interest rates do not affect consolidated results of operations or cash flows. Duke Energy's costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy's plan assets has been affected by declines in the equity market since the third quarter of 2000. As a result, at December 31, 2002, Duke Energy could be required to recognize an additional minimum liability as prescribed by SFAS No. 87 "Employers' Accounting for Pensions" and SFAS No. 132 "Employers' Disclosures about Pensions and Postretirement Benefits." The liability would be recorded as a reduction to OCI, and would not affect net income for 2002. The amount of the liability, if any, will depend upon the asset returns experienced in 2002 and contributions made by Duke Energy to the plans during 2002. Duke Energy is currently evaluating whether to make cash contributions to the plans. The liability recorded or cash contributions to the plans could be material in 2002. Also, pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. When the fair value of the plan assets exceeds the accumulated benefit obligations, the recorded liability will be reduced and OCI will be restored in the Consolidated Balance Sheet. Foreign Currency Risk Duke Energy is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, when possible, transactions are denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy also uses foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure. Since 1991, the Argentine peso had been pegged to the U.S. dollar at a fixed 1:1 exchange ratio. In December 2001, the Argentine government imposed a restriction that limited cash withdrawals above a certain amount and foreign money transfers. Financial institutions were allowed to conduct limited activity as a bank and exchange holiday was announced, and currency exchange activity was essentially halted. In January 2002, the Argentine government announced the creation of a dual-currency system. Subsequently, however, the Argentine government has decided to use a free-floating currency. Duke Energy's investment in Argentine was U.S. dollar functional as of December 31, 2001. Once a functional currency determination has been made, that determination must be adhered to consistently, unless significant changes in economic factors indicate that the entity's functional currency has changed. The events in Argentina required a change. In January 2002, the functional currency of Duke Energy's investment in Argentina changed from the U.S. dollar to the Argentine peso. In compliance with SFAS No. 52, "Foreign Currency Translation," the change in functional currency will be made prospectively. Management believes that the events in Argentina will have no material adverse effect on Duke Energy's future consolidated results of operations, cash flows or financial position. 39 CURRENT ISSUES Environmental. In June 2002, the state of North Carolina passed new clean air legislation that freezes electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007 (rate freeze period), in order for North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state's coal-fired power plants over the next ten years. Management estimates Duke Energy's cost of achieving the proposed emission reductions to be approximately $1.5 billion. Included in the legislation are provisions that allow electric utilities, including Duke Energy, to accelerate the recovery of these compliance costs by amortizing them over seven years (2003-2009). During the rate freeze period, Duke Energy is expected to recover 70% of the total estimated costs of plant improvements. In years six and seven of the recovery period, the NCUC will determine how any remaining costs will be recovered. Notice of Proposed Rulemaking (NOPR) on Standards of Conduct. In September 2001, the Federal Energy Regulatory Commission (FERC) issued a NOPR announcing that it is considering new regulations regarding standards of conduct that would apply uniformly to natural gas pipelines and electric transmitting public utilities that are currently subject to different gas or electric standards. The proposed standards would change how companies and their affiliates interact and share information by broadening the definition of "affiliate" covered by the standards of conduct. The NOPR also seeks comment on whether the standards of conduct should be broadened to include the separation of employees involved in the bundled retail electric sales function from those in the transmission function, as the current standards only require those involved in wholesale sales activities to be separated from the transmission function. Various entities filed comments on the NOPR with the FERC, including Duke Energy which filed in December 2001. In April 2002 the FERC Staff issued an analysis of the comments received by the FERC. In several areas, the staff's analysis reflects important changes to the NOPR. However, with regard to corporate governance, the staff's analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions) and transmission functions within a single company that conducts both electric transmission and marketing functions (such as Duke Power). Duke Energy filed supplemental comments in June 2002. A final rule is expected in the fall of 2002. At its meeting in July 2002, the FERC issued its 600-page Standard Market Design NOPR. The NOPR has major implications for the delivery of electric energy throughout the U.S. Major elements of the FERC proposal include: (a) The use of Network Access Service to replace the existing network and point-to-point services. All customers, including load serving entities on behalf of bundled retail load, would be required to take this service under a new pro forma tariff. There would be no transmission rate pancaking among regions because through-and-out charges would be eliminated. (b) By July 31, 2003, vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems. (c) Congestion management would be provided through the use of Locational Marginal Pricing, a transparent method of pricing transmission congestion costs as a component of energy transactions in a given market. Market participants would be allocated or could purchase Congestion Revenue Rights to manage congestion risk. (d) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification 40 and siting of new transmission facilities in cooperation with states. Some of these features are likely to be highly contested by the various stakeholders. Duke Energy has initiated a detailed review of the NOPR. Initial comments on the NOPR are due to the FERC by October 15, 2002. The FERC has indicated that it intends to issue a final rule by February 2003. While the NOPR is complex, and remains under review, the early indications are that it appears unlikely to materially impact the consolidated financial statements of Duke Energy. Litigation and Contingencies. California Matters. Duke Energy, some of its subsidiaries, and three current or former executives have been named as defendants, among numerous other corporate and individual defendants, in one or more of a total of 14 lawsuits, filed in California on behalf of purchasers of electricity in the State of California, with one suit filed on behalf of a Washington State electricity purchaser. Most of these lawsuits seek class action certification and damages, and other relief, as a result of the defendants' alleged unlawful manipulation of the California wholesale electricity markets. These lawsuits generally allege that the defendants manipulated the wholesale electricity markets in violation of state laws against unfair and unlawful business practices and, in some suits, in violation of state antitrust laws. Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained revenues for sales of electricity and, in some lawsuits, an award of treble damages for alleged violations of state antitrust laws. 41 The first six of these lawsuits were filed in late 2000 through mid-2001 and have been consolidated before a single judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master Amended Complaint in March 2002, which adds additional defendants. The claims against the defendants are similar to those in the original complaints. In April 2002, some defendants, including Duke Energy, filed cross-complaints against various market participants not named as defendants in the plaintiffs' original and amended complaints. Eight of these 14 suits were filed in mid-2002, seven by plaintiffs in California and one by a plaintiff in the State of Washington. These eight suits are being considered for consolidation with the six previously filed lawsuits. These matters are in their earliest stages. Duke Energy is currently evaluating these claims and intends to vigorously defend itself. Duke Energy and its subsidiaries are involved in other legal and regulatory proceedings and investigations related to activities in California. These other activities were disclosed in Duke Energy's Form 10-K for the year ended December 31, 2001, and there have been no new material developments in relation to these issues. Trading Matters. Since April 2002, 16 shareholder class action lawsuits have been filed against Duke Energy: 13 in the United States District Court for the Southern District of New York and three in the United States District Court for the Western District of North Carolina. Some of the lawsuits also name as co-defendants some Duke Energy executives, Duke Energy's independent external auditor and various investment banking firms. In addition, Duke Energy has received a shareholder's derivative notice demanding that it commence litigation against named executives and directors of Duke Energy for alleged breaches of fiduciary duties and insider trading. Duke Energy has also received a second similar shareholder's derivative notice demanding litigation against named executives and directors for alleged failure to prevent damages caused to Duke Energy arising from "round-trip" trading. Duke Energy's response date to the first derivative demand has been extended to after the first of the year 2003. Duke Energy is negotiating a similar agreement with respect to the second derivative demand. The class actions and the threatened shareholder derivative claims arise out of allegations that Duke Energy improperly engaged in the so-called "round trip" trades which resulted in an alleged overstatement of revenues over a three-year period of approximately $1 billion. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys' fees and costs for alleged violations of securities laws. In one of the lawsuits, the plaintiffs assert a common law fraud claim and seek, in addition to compensatory damages, disgorgement and punitive damages. These matters are in their earliest stages. Duke Energy is currently evaluating these claims and intends to vigorously defend itself. In 2002, Duke Energy received and responded to information requests from the FERC, an informal request for information from the SEC, and a subpoena from the Commodity Futures Trading Commission. Duke Energy also received and will respond to a grand jury subpoena issued by the U.S. Attorney's office in Houston. All information requests and subpoenas seek documents and information related to trading activities, including so-called "round-trip" trading. Duke Energy is cooperating with the respective governmental agencies on each of these inquiries. Duke Energy submitted a final report to the SEC based on a review of approximately 750,000 trades made by various Duke Energy subsidiaries between January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review of trading, accounting, and other records, with the assistance of Duke Energy senior legal, corporate risk management and accounting personnel. Duke Energy identified 28 "round-trip" transactions done for the apparent purpose of increasing volumes on the Intercontinental Exchange and 61 "round-trip" transactions done at the direction of one of Duke Energy's traders that did not have a legitimate business purpose and were contrary to corporate policy. Duke Energy determined that the financial impact of these "round trip" transactions was not material. 42 As a result of the trading review, Duke Energy has terminated two employees and put in place additional risk management procedures to improve and strengthen the oversight and controls of its trading operations. Duke Energy has also reconfirmed to employees that engaging in simultaneous or prearranged transactions that lack a legitimate business purpose, or any trading activities that lack a legitimate business purpose, is against company policy. Beginning August 1, 2002, North American trading and marketing functions currently in DENA and DEM, including DETM and the Canadian trading operations, will be consolidated into one group. This organization will develop consistent policies, practices and systems for the entire trading and marketing operation and implement better control systems to improve monitoring and reporting capabilities. Price Mitigation Matters. In November 2001, Nevada Power Company and Sierra Pacific Power Company (collectively, the Companies) filed a complaint with the FERC against DETM. The complaint requests the FERC to mitigate prices in sales contracts between Duke Energy and Nevada Power, and Duke Energy and Sierra Pacific that were entered into between December 7, 2000 and June 20, 2001. The Companies allege that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the California market to be dysfunctional and uncompetitive, and that the California market influenced the contract prices. In April 2002, the FERC issued an order which provides for an evidentiary hearing, establishes refund dates, and requires the parties to participate in settlement negotiations. The parties have reached a settlement pursuant to which the Companies dismissed their complaint against DETM in June 2002. As part of this settlement, Duke Energy has agreed to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to the Companies to fulfill customers' power requirements during the peak summer period. DETM is an intervener in cases against other sellers to these two utilities, but is no longer a respondent in this proceeding. In July 2002, the Sacramento Municipal Utility District (SMUD) filed a complaint with the FERC against DETM requesting that the FERC mitigate unjust and unreasonable prices in four mid- and long-term sales contracts between DETM and SMUD entered into between February 7, 2001 and March 26, 2001. SMUD, alleging that DETM had the ability to exercise market power, claims that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the western markets to be dysfunctional and uncompetitive and that the western markets influenced their price. In support of its request to mitigate the contract price, SMUD relies on the fact that the contract prices are higher than prices in the western U.S. following implementation of the FERC's June 2001 price mitigation plan. SMUD requests the FERC to set "just and reasonable" contract rates and to promptly set a refund effective date. 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 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. Regulatory Matters. North Carolina law requires the Secretary of Revenue to distribute to municipalities a specified portion of the tax revenue derived from electric franchise taxes paid by utilities. However, asserting his constitutional duty to prevent a budget deficit, the Governor issued an Executive Order in February 2001 directing the withholding of distributions to municipalities. In response, several municipalities have passed ordinances to "double tax" Duke Energy's gross receipts effective July 2002. The tax rate is 3.09% on gross receipts and the potential liability, if all municipalities in Duke Energy's service territory passed similar ordinances, is approximately $65 million per year. In July 2002, Duke Energy's request for a hearing before the North Carolina Secretary of Revenue on the new taxes was denied on the grounds that the Secretary has no jurisdiction over tax assessments issued by municipalities. Duke Energy intends to appeal the Secretary's jurisdictional determination to the State Tax Appeal Board. Duke Energy also reserves the option to litigate this issue in state Superior Court. 43 Electric Competition. GridSouth received provisional approval from the FERC in March 2001. However, in July 2001 the FERC ordered GridSouth and other utilities in the Southeast to join in 45 days of mediation to negotiate terms of a Southeast Regional Transmission Organization (RTO). The FERC has not issued an order specifically based on those proceedings. Duke Energy, Carolina Power & Light Company and South Carolina Electric & Gas Company have withdrawn their applications to the Public Service Commission of South Carolina and NCUC to transfer functional control of their electric transmission assets to GridSouth. Efforts surrounding the further development of GridSouth have been suspended until clarification from the FERC is received on matters such as standard market design, transmission upgrade cost allocation and standards of conduct. In addition, Duke Energy is participating in an RTO cost/benefit study initiated by the Southeastern Association of Regulatory Utility Commissioners. New Accounting Standards. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is increased due to the passage of time based on the time value of money until the obligation is settled. Duke Energy is required and plans to adopt the provisions of SFAS No. 143 as of January 1, 2003. To accomplish this, Duke Energy must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Additionally, Duke Energy will be required to develop processes to track and monitor these obligations. Because of the effort needed to comply with the adoption of SFAS No. 143, Duke Energy is currently assessing the new standard but has not yet determined the impact on its consolidated results of operations, cashflows or financial position. In June 2002, the EITF reached a partial consensus on Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and EITF No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods must be reclassified to reflect presentation on a net basis. Also, companies must disclose volumes of physically settled energy trading contracts. Duke Energy is evaluating the impact of this new consensus on the presentation of its Consolidated Statements of Income, but believes it will have a material impact on total revenues and expenses. The partial consensus will have no impact on current or prior net income. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". Duke Energy will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. Subsequent Events. Westcoast, a wholly owned subsidiary of Duke Energy, has entered into an agreement to sell its 60% interest in the Frederickson Power Project for cash proceeds of approximately $100 million. This transaction is subject to regulatory approvals and is expected to be finalized by the end of the third quarter of 2002. In July 2002, Duke Energy International, LLC, a wholly owned subsidiary of Duke Energy, acquired a 103 megawatt gas-fired combined heat and power plant located in northwest France for approximately $69 million. 44 PART II. OTHER INFORMATION Item 1. Legal Proceedings. In June 2001, Duke Energy's subsidiary, Duke Energy Field Services, LLC (DEFS) received two administrative Compliance Orders from the New Mexico Environment Department (NMED) seeking civil penalties for primarily historic air permit matters. One order alleged specific permit non-compliance at 11 facilities that occurred periodically between 1996 and 1999. Allegations under this order related primarily to emissions from some compressor engines in excess of what were then new operating permit limits. The other order alleged numerous unexcused excursions from an hourly permit limit arising from upset events at one facility's sulfur recovery unit between 1997 and 2001. NMED applied its civil penalty policy to the alleged violations and calculated the penalties to be $10 million in the aggregate. In May 2002, DEFS and NMED entered into a Settlement Agreement which resolves all aspects of the June 2001 Compliance Orders. Under the terms of the Settlement Agreement, no penalty will be assessed, and DEFS has agreed to undertake upgrades at several of its facilities in New Mexico that will significantly reduce emissions and will also ensure those facilities are achieving state ambient air quality standards. DEFS was in discussion with the Oklahoma Department of Environmental Quality (ODEQ) regarding apparent non-compliance issues relating to DEFS' Title V Clean Air Act Operating permits at its Oklahoma facilities, primarily consisting of compliance issues disclosed to the ODEQ pursuant to permit requirements or otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance issues relate to various specific and detailed terms of the Title V permits, including, separate filing requirements, engine testing procedural requirements, certification requirements, and quarterly emissions testing obligations. In May 2002, DEFS and ODEQ entered into a Consent Order to address and resolve all of the items of non-compliance with Title V permits as discussed above. Under the Consent Order, DEFS agreed to pay a civil penalty of $85,050 and install pollution control equipment on some of its compressor engines to achieve significant emissions reductions at a cost of approximately $482,000. The items of non-compliance have been corrected, and the installation of the pollution controls is presently underway. For additional information concerning litigation and other contingencies, see Note 7 to the Consolidated Financial Statements, "Commitments and Contingencies," and Item 3, "Legal Proceedings," and Note 15 to the Consolidated Financial Statements, "Commitments and Contingencies," included in Duke Energy's Form 10-K for December 31, 2001, 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. At the Duke Energy Corporation Annual Meeting of Shareholders held April 25, 2002, the shareholders elected G. Alex Bernhardt, Sr., William A. Coley, Max Lennon and Leo E. Linbeck, Jr. to serve as Class II directors with terms expiring in 2005. James T. Rhodes was elected to serve as a Class I director with a term expiring in 2004. The shareholders also voted to ratify the selection of Deloitte & Touche LLP to act as independent auditors to make an examination of Duke Energy's accounts for the year 2002. The shareholders approved four proposals to amend Duke Energy's Articles of Incorporation. The first proposal was to update the corporate purpose clause, with 644,377,433 shares voting for the proposal, 4,042,506 shares voting against the proposal and 5,784,941 shares abstaining. The second proposal was to authorize a new class of Preferred Stock, to be known as "Serial Preferred Stock," consisting of 20,000,000 shares issuable in series, with 455,981,860 shares voting for the proposal, 84,631,821 shares voting against the proposal and 7,134,191 shares abstaining. The third proposal was to require a majority vote of holders of outstanding shares to adopt, amend or repeal the by-laws, with 446,247,130 shares voting for the proposal, 95,071,788 shares voting against the proposal and 6,429,922 shares abstaining. The fourth 45 proposal was to decrease the permissible range of the size of the Board of Directors to between nine and 18 members, with 638,665,652 shares voting for the proposal, 9,577,705 shares voting against the proposal and 5,962,021 shares abstaining. The shareholders did not approve four shareholder proposals presented in the proxy statement for the meeting. With respect to the proposal to invest in alternative energy sources, 22,393,862 shares voted for the proposal, 504,311,559 shares voted against the proposal and 21,039,055 shares abstained. With respect to the proposal relating to the role of the Board of Directors in long-term strategic planning, 28,895,916 shares voted for the proposal, 500,450,742 shares voted against the proposal and 18,398,945 shares abstained. With respect to the proposal relating to the appointment of independent auditors who only render audit services, 187,558,432 shares voted for the proposal, 329,094,231 shares voted against the proposal and 31,068,883 shares abstained. With respect to the proposal relating to a study of the risk and responsibility for public harm due to Duke Energy's nuclear program, 55,181,575 shares voted for the proposal, 469,378,818 shares voted against the proposal and 23,185,089 shares abstained. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits Exhibit Number 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K A Current Report on Form 8-K filed on April 15, 2002 contained disclosures under Item 5, Other Events and Item 7, Exhibits. 46 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 August 14, 2002 /s/ Robert P. Brace --------------------- Robert P. Brace Executive Vice President and Chief Financial Officer August 14, 2002 /s/ Keith G. Butler --------------------- Keith G. Butler Senior Vice President and Controller 47 EX-99.1 3 dex991.txt CERTIFICATION Exhibit 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Duke Energy Corporation ("Duke Energy") on Form 10-Q for the period ending June 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Richard B. Priory, Chairman of the Board, President and Chief Executive Officer of Duke Energy, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Duke Energy. /s/ Richard B. Priory Richard B. Priory Chairman of the Board, President and Chief Executive Officer August 14, 2002 EX-99.2 4 dex992.txt CERTIFICATION Exhibit 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Duke Energy Corporation ("Duke Energy") on Form 10-Q for the period ending June 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert P. Brace, Executive Vice President and Chief Financial Officer of Duke Energy, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Duke Energy. /s/ Robert P. Brace Robert P. Brace Executive Vice President and Chief Financial Officer August 14, 2002 -----END PRIVACY-ENHANCED MESSAGE-----