-----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, O++uAIuBAdUczcyUyawj199Hu7WxJpJ7xdFWqCAoeqjJgm5C0z/qspPJpLSqwohW 0M+WLNKRzyoHjFL4U15kvQ== 0001004440-02-000111.txt : 20020415 0001004440-02-000111.hdr.sgml : 20020415 ACCESSION NUMBER: 0001004440-02-000111 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20020319 ITEM INFORMATION: Other events ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 20020319 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 02578316 BUSINESS ADDRESS: STREET 1: 39 WEST LEXINGTON STREET CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107833624 MAIL ADDRESS: STREET 1: 39 WEST LEXINGTON STREET CITY: BALTIMORE STATE: MD ZIP: 21201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONSTELLATION ENERGY GROUP INC CENTRAL INDEX KEY: 0001004440 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 521964611 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-25931 FILM NUMBER: 02578317 BUSINESS ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345685 MAIL ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 FORMER COMPANY: FORMER CONFORMED NAME: RH ACQUISITION CORP DATE OF NAME CHANGE: 19951205 FORMER COMPANY: FORMER CONFORMED NAME: CONSTELLATION ENERGY CORP DATE OF NAME CHANGE: 19951220 8-K 1 f8k.txt FORM 8K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): March 19, 2002 Commission Exact name of registrant IRS Employer File Number as specified in its charter Identification No. ----------- ---------------------------------- ------------------ 1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 Maryland ----------------------------------- (State or other jurisdiction of incorporation for each registrant) 250 W. Pratt Street, Baltimore, Maryland 21201 --------------------------------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrants' telephone number, including area code: (410) 234-5000 Not Applicable ------------------------------------------------------------------------- (Former name or former address, if changed since last report) ITEM 5. Other Events - ------ ------------ Attached to this Current Report on Form 8-K are the Computation of the Ratio of Earnings to Fixed Charges (Exhibit No. 12), consent of the Independent Accountants (Exhibit No. 23), and the audited Consolidated Financial Statements and Notes to Consolidated Financial Statements (Exhibit No. 99) of Constellation Energy for the year ended December 31, 2001. Recent Events - ------------- Sale of Orion Power Holdings, Inc. (Orion) - ------------------------------------------ In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares of Orion for $26.80 per share, including the shares we owned of Orion. We received cash proceeds of $454.1 million and recognized a pre-tax gain of $255.5 million on the sale of our investment. Sale of Investment in Corporate Office Properties Trust (COPT) - -------------------------------------------------------------- In March 2002, we sold all of our COPT equity-method investment, approximately 8.9 million shares, as part of a public offering. We received cash proceeds of $101.3 million on the sale, which approximates the book value of our investment. High Desert Contract - -------------------- In February 2002, the California Department of Water Resources (Department) filed a claim with the Federal Energy Regulatory Commission (FERC) that all long-term contracts for power supply that the Department entered into in the first quarter of 2001, which includes the contracts related to our High Desert project, were not just and reasonable. The Department is requesting the FERC to terminate the contracts entirely or, at least, modify the prices to terms that the FERC considers just and reasonable. Currently, we are discussing the renegotiations of our contracts with the Department. We cannot estimate the timing or impact of the FERC proceedings or the renegotiations of our contracts. Credit Ratings - -------------- All three rating agencies recently completed reviews of Constellation Energy's and Baltimore Gas and Electric Company's (BGE) ratings. FitchRatings affirmed its ratings of Constellation Energy. Standard & Poors Rating Group downgraded Constellation Energy's commercial paper from A-1 to A-2 and senior unsecured debt from A- to BBB+. In addition, Moody's Investors Service downgraded Constellation Energy's commercial paper from P-1 to P-2 and senior unsecured debt from A3 to Baa1. All Constellation Energy ratings have stable outlooks. Moody's Investors Service and FitchRatings recently affirmed the ratings of BGE. Standard & Poors Rating Group downgraded BGE commercial paper from A-1 to A-2, senior unsecured debt from A to BBB+, mortgage bonds from AA- to A, and Trust Originated Preferred Securities and Preference Stock from A- to BBB. All BGE ratings have stable outlooks. At the date of this report, our credit ratings were as follows: Standard & Moody's Poors Investors Rating Group Service FitchRatings ------------------------------------ ------------- ------------ ------------ Constellation Energy Commercial Paper A-2 P-2 F-2 Senior Unsecured Debt BBB+ Baa1 A- BGE Commercial Paper A-2 P-1 F-1 Mortgage Bonds A A1 A+ Senior Unsecured Debt BBB+ A2 A Trust Originated Preferred Securities and Preference Stock BBB Baa1 A- 2 Forward Looking Statements - -------------------------- We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "expects," "intends," "plans," and other similar words. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to: o the timing and extent of changes in commodity prices for energy including coal, natural gas, oil, and electricity, o the timing and extent of deregulation of, and competition in, the energy markets in North America, and the rules and regulations adopted on a transitional basis in those markets, o the conditions of the capital markets generally, which are affected by interest rates and general economic conditions, as well as Constellation Energy and BGE's ability to maintain their current credit ratings, o the effectiveness of Constellation Energy's risk management policies and procedures and the ability of our counterparties to satisfy their financial commitments, o the liquidity and competitiveness of wholesale markets for energy commodities, o operational factors affecting the start-up or ongoing commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control, the inability of BGE to recover all its costs associated with providing electric retail customers service during the electric rate freeze period, o the effect of weather and general economic and business conditions on energy supply, demand, and prices, o regulatory or legislative developments that affect demand for energy, or increase costs, including costs related to nuclear power plants, safety, or environmental compliance, o the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in applying mark-to-market accounting, such as, variable contract quantities and the value of mark-to-market assets and liabilities determined using models, o cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities, or the outcome of pending appeals regarding the Maryland PSC's orders on electric deregulation, and the transfer of BGE's generation assets to affiliates, and o operation of our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause. Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see our other periodic reports filed with the SEC for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report. Changes may occur after that date, and we do not assume responsibility to update these forward looking statements. 3 ITEM 7. Financial Statements and Exhibits - ------- --------------------------------- (c) Exhibit No. 12 Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges. (c) Exhibit No. 23 Consent of PricewaterhouseCoopers LLP, Independent Accountants. (c) Exhibit No. 99 Consolidated Financial Statements and Notes to Consolidated Financial Statements of Constellation Energy Group, Inc. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. CONSTELLATION ENERGY GROUP, INC. ------------------------------------------- (Registrant) BALTIMORE GAS AND ELECTRIC COMPANY ------------------------------------------- (Registrant) Date: March 19, 2002 /s/ E. Follin Smith -------------- ------------------------------------------------- E. Follin Smith, Senior Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 4 EX-12 4 ex12a.txt EX 12A Exhibit No. 12 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended ---------------------------------------------------------------------- December December December December December 2001 2000 1999 1998 1997 -------------------------- ------------ ------------ ------------ (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effect of Change in Accounting Principle) $ 82.4 $ 345.3 $ 326.4 $ 305.9 $ 254.1 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 29.7 221.4 182.5 169.3 145.1 ----------- ------------ ------------ ------------ ------------ Adjusted Income $ 112.1 $ 566.7 $ 508.9 $ 475.2 $ 399.2 ----------- ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 226.1 $ 261.5 $ 245.7 $ 255.3 $ 234.2 Earnings Required for BGE Preference Stock Dividends 21.4 21.9 21.0 33.8 45.1 Capitalized Interest 55.8 21.1 2.7 3.6 8.4 Interest Factor in Rentals 2.0 2.2 1.8 1.9 1.9 ----------- ------------ ------------ ------------ ------------ Total Fixed Charges $ 305.3 $ 306.7 $ 271.2 $ 294.6 $ 289.6 ----------- ------------ ------------ ------------ ------------ Earnings (1) $ 361.6 $ 852.3 $ 777.4 $ 766.2 $ 680.4 =========== ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 1.18 2.78 2.87 2.60 2.35
(1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss and cumulative effect of change in accounting principle) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of unconsolidated subsidiaries, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest. EX-23 5 consent.txt EX NO 23 Exhibit No. 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 and Form S-8 (Nos. 333-81352, 333-36380, 333-59601, 33-57658, 333-56572, 333-24705, and 33-49801, and 33-59545, 333-45051, 333-46980 and 333-81292, respectively) of Constellation Energy Group, Inc. of our report dated January 21, 2002 relating to the financial statements of Constellation Energy Group, Inc., which appear in this Form 8-K. /s/ PricewaterhouseCoopers LLP - ------------------------------ PricewaterhouseCoopers LLP Baltimore, Maryland March 19, 2002 EX-99 6 ex99.txt EX NO 99 Exhibit No. 99 Report of Independent Accountants - --------------------------------- To the Shareholders of Constellation Energy Group, Inc. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, cash flows, common shareholders' equity, capitalization, and income taxes present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries ("the Company") at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). /s/ PricewaterhouseCoopers LLP - ------------------------------ PricewaterhouseCoopers LLP Baltimore, Maryland January 21, 2002 1 Consolidated Statements of Income Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Nonregulated revenues $1,214.4 $1,114.0 $1,105.6 Regulated electric revenues 2,039.6 2,134.7 2,258.8 Regulated gas revenues 674.3 603.8 476.5 - ----------------------------------------------------------------------------------------------------------------------------------- Total revenues 3,928.3 3,852.5 3,840.9 Expenses Operating expenses 2,392.2 2,311.4 2,339.6 Workforce reduction costs 105.7 7.0 -- Contract termination related costs 224.8 -- -- Impairment losses and other costs 202.1 -- 64.3 Depreciation and amortization 419.1 470.0 449.8 Taxes other than income taxes 226.6 221.5 227.3 - ----------------------------------------------------------------------------------------------------------------------------------- Total expenses 3,570.5 3,009.9 3,081.0 - ----------------------------------------------------------------------------------------------------------------------------------- Income from Operations 357.8 842.6 759.9 Other Income 1.3 4.2 7.9 - ----------------------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 359.1 846.8 767.8 Fixed Charges Interest expense 283.2 282.4 248.0 Interest capitalized and allowance for borrowed funds used during construction (57.6) (24.2) (6.5) BGE preference stock dividends 13.2 13.2 13.5 - ----------------------------------------------------------------------------------------------------------------------------------- Total fixed charges 238.8 271.4 255.0 - ----------------------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 120.3 575.4 512.8 Income Taxes 37.9 230.1 186.4 - ----------------------------------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle 82.4 345.3 326.4 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5) -- -- (66.3) Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 (see Note 1) 8.5 -- -- - ----------------------------------------------------------------------------------------------------------------------------------- Net Income $ 90.9 $ 345.3 $ 260.1 =================================================================================================================================== Earnings Applicable to Common Stock $ 90.9 $ 345.3 $ 260.1 =================================================================================================================================== Average Shares of Common Stock Outstanding 160.7 150.0 149.6 Earnings Per Common Share and Earnings Per Common Share --Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle $ .52 $2.30 $2.18 Extraordinary Loss -- -- (.44) Cumulative Effect of Change in Accounting Principle .05 -- -- - ----------------------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share and Earnings Per Common Share--Assuming Dilution $ .57 $2.30 $1.74 ===================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 2 Consolidated Statements of Comprehensive Income Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions) Net Income $ 90.9 $ 345.3 $ 260.1 Other comprehensive income, net of taxes Financial securities 124.5 18.6 3.9 Hedging instruments 102.6 -- -- Minimum pension liability (44.7) -- -- - ----------------------------------------------------------------------------------------------------------------------------------- Comprehensive Income Before Cumulative Effect of Change in Accounting Principle 273.3 363.9 264.0 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6 (35.5) -- -- - ----------------------------------------------------------------------------------------------------------------------------------- Comprehensive Income $ 237.8 $ 363.9 $ 264.0 ===================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 3 Consolidated Balance Sheets Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 72.4 $ 182.7 Accounts receivable (net of allowance for uncollectibles of $22.8 and $21.3, respectively) 738.9 792.6 Trading securities 178.2 189.3 Mark-to-market energy assets 398.4 453.1 Fuel stocks 108.0 78.2 Materials and supplies 196.3 151.3 Prepaid taxes other than income taxes 93.4 73.5 Other 74.6 52.8 - ----------------------------------------------------------------------------------------------------------------------------------- Total current assets 1,860.2 1,973.5 - ----------------------------------------------------------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 210.7 290.3 Investments in power projects 499.1 510.6 Investment in Orion Power Holdings, Inc. 442.5 192.0 Financial investments 60.7 161.0 Nuclear decommissioning trust funds 683.5 228.7 Net pension asset -- 93.2 Mark-to-market energy assets 1,819.8 2,069.3 Other 207.4 123.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total investments and other assets 3,923.7 3,668.1 - ----------------------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment Regulated property, plant and equipment Plant in service 4,862.4 4,780.3 Construction work in progress 81.8 75.3 Plant held for future use 4.5 4.5 - ----------------------------------------------------------------------------------------------------------------------------------- Total regulated property, plant and equipment 4,948.7 4,860.1 Nonregulated generation property, plant and equipment 6,551.1 5,286.8 Other nonregulated property, plant and equipment 192.9 147.0 Nuclear fuel (net of amortization) 169.5 128.3 Accumulated depreciation (4,161.8) (3,756.7) - ----------------------------------------------------------------------------------------------------------------------------------- Net property, plant and equipment 7,700.4 6,665.5 - ----------------------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 463.8 514.9 Other 129.5 117.3 - ----------------------------------------------------------------------------------------------------------------------------------- Total deferred charges 593.3 632.2 - ----------------------------------------------------------------------------------------------------------------------------------- Total Assets $14,077.6 $12,939.3 ===================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 4 Consolidated Balance Sheets Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 975.0 $ 243.6 Current portion of long-term debt 1,406.7 906.6 Accounts payable 534.4 750.0 Mark-to-market energy liabilities 323.3 358.2 Dividends declared 23.0 66.5 Other 297.1 250.8 - ----------------------------------------------------------------------------------------------------------------------------------- Total current liabilities 3,559.5 2,575.7 - ----------------------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,431.0 1,353.2 Mark-to-market energy liabilities 1,476.5 1,636.3 Net pension liability 173.3 -- Postretirement and postemployment benefits 330.9 265.2 Deferred investment tax credits 93.4 101.4 Other 266.9 484.2 - ----------------------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,772.0 3,840.3 - ----------------------------------------------------------------------------------------------------------------------------------- Capitalization Long-term debt 2,712.5 3,159.3 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 3,843.6 3,174.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total capitalization 6,746.1 6,523.3 - ----------------------------------------------------------------------------------------------------------------------------------- Commitments, Guarantees, and Contingencies (see Note 11) Total Liabilities and Capitalization $14,077.6 $12,939.3 ===================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 5 Consolidated Statements of Cash Flows Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 90.9 $ 345.3 $260.1 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle (8.5) -- -- Extraordinary loss -- -- 66.3 Depreciation and amortization 468.9 524.8 505.9 Deferred income taxes (26.5) 42.1 13.0 Investment tax credit adjustments (8.1) (8.4) (8.6) Deferred fuel costs 37.6 2.8 (61.1) Accrued pension and postemployment benefits 55.3 27.9 36.1 Gain on sale of investments (40.7) (64.1) -- Loss (gain) on sale of subsidiaries and plant assets 43.3 (13.3) -- Deregulation transition cost -- 24.0 -- Workforce reduction costs 105.7 7.0 -- Contract termination related costs 26.2 -- -- Impairment losses and other costs 158.7 -- 64.3 Equity in earnings of affiliates and joint ventures (net) 2.0 (5.3) (7.6) Changes in mark-to-market energy assets and liabilities 109.5 (379.6) (114.3) Changes in other current assets (57.7) (230.7) (216.4) Changes in other current liabilities (218.8) 406.2 121.0 Other (164.5) 172.2 20.3 - ----------------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 573.3 850.9 679.0 - ----------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (1,318.3) (1,079.0) (616.5) Acquisition of Nine Mile Point (382.7) -- -- Sale of (investment in) Orion 26.2 (101.5) (97.7) Contributions to nuclear decommissioning trust funds (22.0) (13.2) (17.6) Purchases of marketable equity securities (33.2) (80.8) (27.3) Sales of marketable equity securities 132.6 110.2 34.9 Proceeds from the sale of property, plant, and equipment 112.0 20.8 -- Other investments 12.7 37.0 109.1 - ----------------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (1,472.7) (1,106.5) (615.1) - ----------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings 731.4 (127.9) 371.5 Proceeds from issuance of Long-term debt 1,175.2 1,374.0 302.8 Common stock 504.4 35.9 9.6 Repayment of long-term debt (1,510.2) (697.0) (584.4) Redemption of preference stock -- -- (7.0) Common stock dividends paid (120.7) (250.7) (251.1) Other 9.0 11.3 13.7 - ----------------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities 789.1 345.6 (144.9) - ----------------------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (110.3) 90.0 (81.0) Cash and Cash Equivalents at Beginning of Year 182.7 92.7 173.7 - ----------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 72.4 $ 182.7 $ 92.7 =================================================================================================================================== Other Cash Flow Information: - ---------------------------- Cash paid during the year for: Interest (net of amounts capitalized) $238.3 $268.2 $245.3 Income taxes $101.5 $184.7 $165.6
Non-Cash Transaction: - --------------------- In connection with our purchase of Nine Mile Point, the fair value of the net assets purchased was $770.8 million. We paid $382.7 million in cash, including settlement costs, and incurred a sellers' note of $388.1 million as discussed further in Note 14 on page 40. See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 6 Consolidated Statements of Common Shareholders' Equity Constellation Energy Group, Inc. and Subsidiaries
Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 2001, 2000, and 1999 Shares Amount Earnings Income Amount - ----------------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, number of shares in thousands) Balance at December 31, 1998 149,246 $1,485.1 $1,490.3 $ 20.5 $2,995.9 Net income 260.1 260.1 Common stock dividend declared ($1.68 per share) (251.3) (251.3) Common stock issued 310 9.6 9.6 Other (0.7) (0.7) Net unrealized gain on securities, net of taxes of $3.2 3.9 3.9 - ----------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 149,556 1,494.0 1,499.1 24.4 3,017.5 Net income 345.3 345.3 Common stock dividend declared ($1.68 per share) (251.8) (251.8) Common stock issued 976 35.9 35.9 Other 8.8 (0.3) 8.5 Net unrealized gain on securities, net of taxes of $9.5 18.6 18.6 - ----------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 150,532 1,538.7 1,592.3 43.0 3,174.0 Net income 90.9 90.9 Common stock dividend declared ($.48 per share) (77.1) (77.1) Common stock issued 13,176 504.4 504.4 Other (0.9) 5.4 4.5 Cumulative effect of change in accounting principle, net of taxes of $22.6 (35.5) (35.5) Net unrealized gain on securities, net of taxes of $71.8 124.5 124.5 Net unrealized gain on hedging instruments, net of taxes of $65.6 102.6 102.6 Minimum pension liability, net of taxes of $29.3 (44.7) (44.7) - ----------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 163,708 $2,042.2 $1,611.5 $189.9 $3,843.6 ===================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 7 Consolidated Statements of Capitalization Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------------------- Long-Term Debt (In millions) Long-term debt of Constellation Energy 7 7/8% Notes, due April 1, 2005 $ 300.0 $ 300.0 Floating rate notes, due April 4, 2003 -- 200.0 Extendible notes, due June 21, 2010 -- 300.0 Floating rate reset notes, due March 15, 2002 -- 200.0 Floating rate notes, due January 17, 2002 635.0 -- - ----------------------------------------------------------------------------------------------------------------------------------- Total long-term debt of Constellation Energy 935.0 1,000.0 - ----------------------------------------------------------------------------------------------------------------------------------- Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE effective July 1, 2000 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Floating rate pollution control loan, due June 1, 2027 8.8 8.8 5 1/2% Installment series, due July 15, 2002 6.7 7.6 District Cooling facilities loan, due December 1, 2031 25.0 -- Loans under revolving credit agreements 46.0 34.0 11% Installment note, due November 7, 2006 388.1 -- Mortgage and construction loans Floating rate mortgage notes and construction loans, due through 2005 13.8 51.3 Other mortgage notes ranging from 4.25% to 9.65% due March 15, 2009 to November 1, 2033 19.7 20.3 Unsecured notes -- 287.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total long-term debt of nonregulated businesses 769.1 670.0 - ----------------------------------------------------------------------------------------------------------------------------------- First Refunding Mortgage Bonds of BGE 8 3/8% Series, due August 15, 2001 -- 122.2 7 1/4% Series, due July 1, 2002 124.0 124.0 6 1/2% Series, due February 15, 2003 124.8 124.8 6 1/8% Series, due July 1, 2003 124.9 124.9 5 1/2% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 111.5 111.5 7 1/2% Series, due January 15, 2007 123.5 123.5 6 5/8% Series, due March 15, 2008 124.9 124.9 7 1/2% Series, due March 1, 2023 98.1 109.9 7 1/2% Series, due April 15, 2023 84.0 84.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total First Refunding Mortgage Bonds of BGE 1,040.7 1,174.7 - ----------------------------------------------------------------------------------------------------------------------------------- Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 -- Floating rate reset notes, due February 5, 2002 200.0 -- Floating rate reset notes, due October 19, 2001 -- 200.0 Medium-term notes, Series B 23.1 23.1 Medium-term notes, Series C 25.5 25.5 Medium-term notes, Series D 68.0 128.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 140.0 200.0 Medium-term notes, Series H -- 27.0 6.75% Remarketable or redeemable securities, due December 15, 2012 173.0 173.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total other long-term debt of BGE 1,129.6 976.6 - ----------------------------------------------------------------------------------------------------------------------------------- BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 Unamortized discount and premium (5.2) (5.4) Current portion of long-term debt (1,406.7) (906.6) - ----------------------------------------------------------------------------------------------------------------------------------- Total long-term debt $2,712.5 $3,159.3 - -----------------------------------------------------------------------------------------------------------------------------------
continued on next page See Notes to Consolidated Financial Statements. 8 Consolidated Statements of Capitalization Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------------------- (In millions) BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 $40.0 $40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total preference stock not subject to mandatory redemption 190.0 190.0 - ----------------------------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 163,707,950 and 150,531,716 shares issued and outstanding at December 31, 2001 and 2000, respectively. (At December 31, 2001, 11,797,976 shares were reserved for the Shareholder Investment Plan and 6,000,000 were reserved for the long-term incentive plans.) 2,042.2 1,538.7 Retained earnings 1,611.5 1,592.3 Accumulated other comprehensive income 189.9 43.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 3,843.6 3,174.0 - ----------------------------------------------------------------------------------------------------------------------------------- Total Capitalization $6,746.1 $6,523.3 ===================================================================================================================================
See Notes to Consolidated Financial Statements. 9 Consolidated Statements of Income Taxes Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999 - -------------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Income Taxes Current Federal $45.5 $148.2 $176.3 State 27.0 48.2 5.7 - -------------------------------------------------------------------------------------------------------------------------------- Current taxes charged to expense 72.5 196.4 182.0 Deferred Federal (22.4) 53.9 5.8 State (4.1) (11.8) 7.2 - -------------------------------------------------------------------------------------------------------------------------------- Deferred taxes charged to expense (26.5) 42.1 13.0 Investment tax credit adjustments (8.1) (8.4) (8.6) - -------------------------------------------------------------------------------------------------------------------------------- Income taxes per Consolidated Statements of Income $37.9 $230.1 $186.4 ================================================================================================================================ Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends) $133.5 $588.6 $526.3 Statutory federal income tax rate 35% 35% 35% - -------------------------------------------------------------------------------------------------------------------------------- Income taxes computed at statutory federal rate 46.7 206.0 184.2 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 5.6 12.6 15.3 Allowance for equity funds used during construction (1.1) (0.9) (2.2) Amortization of deferred investment tax credits (8.1) (8.4) (8.6) Tax credits flowed through to income (13.4) (6.5) (3.2) Amortization of deferred tax rate differential on regulated activities (2.1) (2.9) (3.0) State income taxes, net of federal income tax benefit 13.5 31.7 8.2 Other (3.2) (1.5) (4.3) - -------------------------------------------------------------------------------------------------------------------------------- Total income taxes $ 37.9 $230.1 $186.4 ================================================================================================================================ Effective income tax rate 28.4% 39.1% 35.4% At December 31, 2001 2000 - -------------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,156.0 $1,135.5 Income taxes recoverable through future rates 31.4 32.8 Deferred termination and postemployment costs 7.0 13.6 Deferred fuel costs 11.7 24.9 Power marketing and risk management activities 776.4 819.4 Deferred electric generation-related regulatory assets 87.1 93.7 Financial investments and hedging instruments 153.9 42.6 Other 140.9 135.6 - -------------------------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 2,364.4 2,298.1 Deferred tax assets Accrued pension and postemployment benefit costs 132.7 76.5 Deferred investment tax credits 35.1 35.5 Nuclear decommissioning liability 32.1 28.2 Power marketing and risk management activities 549.1 638.2 Reduction of investments 82.3 29.8 Other 102.1 136.7 - -------------------------------------------------------------------------------------------------------------------------------- Total deferred tax assets 933.4 944.9 - -------------------------------------------------------------------------------------------------------------------------------- Deferred tax liability, net $1,431.0 $1,353.2 ================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 10 Notes to Consolidated Financial Statements - ------------------------------------------ Note 1. Significant Accounting Policies - -------------------------------------------------------------------------------- Nature of Our Business - ---------------------- Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business generates and markets wholesale electricity in North America. BGE is an electric and gas public transmission and distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. We describe our operating segments in Note 3 on page 20. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. Reference in this report to the "utility business" is to BGE. Consolidation Policy - -------------------- We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method. Consolidation - ------------- We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate intercompany balances and transactions when we consolidate these accounts. The Equity Method - ----------------- We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report: o our interest in the entity as an investment in our Consolidated Balance Sheets, and o our percentage share of the earnings from the entity in our Consolidated Statements of Income. The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation. The Cost Method - --------------- We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method. Regulation of Utility Business - ------------------------------ The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) certain utility expenses and income as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets and liabilities further in Note 6 on page 25. In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. On November 10, 1999, the Maryland PSC issued a Restructuring Order that we believe provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises--Accounting for the Discontinuation of FASB Statement No. 71 and EITF 97-4 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71, as that business remains regulated. We discuss this further in Note 5 on page 23. 11 Revenues - -------- Nonregulated Businesses - ----------------------- Our subsidiary, Constellation Power Source, uses the mark-to-market method of accounting, as discussed below, to account for power marketing activities. We record all other nonregulated revenues in the period earned for services rendered, commodities or products delivered, or contracts settled. Equity in earnings from our investments in power projects is included in revenues. Power marketing activities include new origination transactions and risk management activities using contracts for energy, other energy-related commodities, and related derivative contracts. We account for these activities using the mark-to-market method of accounting as required by EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Under the mark-to-market method of accounting, we record the fair value of commodity and derivative contracts as mark-to-market energy assets and liabilities at the time of contract execution. We record reserves to reflect uncertainties associated with certain estimates inherent in the determination of fair value. Mark-to-market energy revenues include: o the fair value of new transactions at origination, o unrealized gains and losses from changes in the fair value of open positions, o net gains and losses from realized transactions, and o changes in reserves. We record the changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income. Mark-to-market energy assets and liabilities are comprised of a combination of energy and energy-related derivative and non-derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices used to determine fair value reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, it is possible that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material. Certain power marketing and risk management transactions entered into under master agreements and other arrangements provide our merchant energy business with a right of setoff in the event of bankruptcy or default by the counterparty. We report such transactions net in the balance sheets in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts. Regulated Utility - ----------------- We record utility revenues when we provide service to customers. Fuel and Purchased Energy Costs - ------------------------------- We incur costs for: o the fuel we use to generate electricity, o purchases of electricity from others, and o natural gas that we resell. These costs are included in "Operating expenses" in our Consolidated Statements of Income. We discuss each of these separately below. Fuel Used to Generate Electricity and Purchases of Electricity From Others - -------------------------------------------------------------------------- Effective July 1, 2000, these costs are recorded as incurred. Historically and until July 1, 2000, we were allowed to recover our costs of electric fuel under the electric fuel rate clause set by the Maryland PSC. Under the electric fuel rate clause, we charged our electric customers for: o the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and o the net cost of purchases and sales of electricity. We charged the actual costs of these items to customers with no profit to us. To do this, we had to keep track of what we spent and what we collected from customers under the fuel rate in a given period. Usually these two amounts were not the same because there was a difference between the time we spent the money and the time we collected it from our customers. Under the electric fuel rate clause, we deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate in a given period. We either billed or refunded our customers that difference in the future. As a result of the Restructuring Order, the fuel rate was discontinued effective July 1, 2000. We discuss this further in Note 6 on page 25. Natural Gas - ----------- We charge our gas customers for the natural gas they purchase from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this note. However, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market-based rates incentive mechanism. Under market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed price contracts are not subject to sharing under the market-based rates incentive mechanism. 12 Risk Management - --------------- We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities as discussed further in Note 12 on page 37. We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as discussed later in this note, with gains or losses recorded in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization, in anticipation of planned financing transactions. Any gain or loss on the hedges will be reclassified from "Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur. Our merchant energy and regulated gas businesses use derivative and non-derivative instruments to manage changes in their respective commodity prices as discussed in more detail below. Merchant Energy Business - ------------------------ The power marketing operation manages market risk on a portfolio basis, subject to established risk management policies. The power marketing operation uses a variety of derivative and non-derivative instruments, including: o forward contracts, which commit us to purchase or sell energy commodities in the future; o futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date; o swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity; and o option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price. As part of its overall portfolio, the power marketing operation manages the commodity price risk of our electric generation facilities, including power sales, fuel purchases, emission credits, weather risk, and the market risk of outages. In order to manage this risk, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. The objectives for entering into such hedges include: o fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations, and o fixing the price of a portion of anticipated fuel purchases for the operation of our power plants. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors. Under the provisions of SFAS No. 133, we record gains and losses on derivative contracts designated as cash-flow hedges of firm commitments or anticipated transactions in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization prior to the settlement of the anticipated hedged physical transaction. We reclassify these gains or losses into earnings upon settlement of the underlying hedged transaction. We record derivatives used for hedging activities from our merchant energy business in "Other assets," and in "Other deferred credits and other liabilities," on the Consolidated Balance Sheets. Regulated Electric Business - --------------------------- Under the Restructuring Order, effective July 1, 2000, BGE's residential rates are frozen for a six-year period, and its commercial and industrial rates are frozen for four to six years. BGE entered into standard offer service arrangements with Constellation Power Source and Allegheny Energy Supply Company to provide the energy and capacity required to meet its standard offer service obligations through June 30, 2006. Regulated Gas Business - ---------------------- We use basis swaps in the winter months (November through March) to hedge our price risk associated with natural gas purchases under our market-based rates incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps to hedge our price risk associated with our off-system gas sales. The fixed portion represents a specific dollar amount that we will pay or receive, and the floating portion represents a fluctuating amount based on a published index that we will receive or pay. Our regulated gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. BGE's off-system gas sales activities represent trading activities under EITF 98-10. Accordingly, we use mark-to-market accounting to record these transactions. The trading activities relating to our off-system gas sales were not material at December 31, 2001 and 2000. We defer, as unrealized gains or losses, the changes in fair value of the swap agreements under the market-based rates incentive mechanism and the customers' portion of off-system gas sales in our Consolidated Balance Sheets. When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off-system gas sales in earnings as a component of gas costs. 13 Credit Risk - ----------- Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily through Constellation Power Source. Constellation Power Source uses credit policies to manage its credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements. Constellation Power Source measures credit risk as the replacement cost for open energy commodity and derivative positions plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity the power marketing operation had contracted for), we could sustain a loss that could have a material impact on our financial results. Electric and gas utilities, cooperatives, and energy marketers comprise the majority of counterparties underlying our assets from power marketing and risk management activities. We held cash collateral from counterparties totaling $3.5 million as of December 31, 2001 and $103.3 million as of December 31, 2000. These amounts are included in "Other deferred credits and other liabilities" in our Consolidated Balance Sheets. Taxes - ----- We summarize our income taxes in our Consolidated Statements of Income Taxes on page 10. As you read this section, it may be helpful to refer to those statements. Income Tax Expense - ------------------ We have two categories of income taxes in our Consolidated Statements of Income--current and deferred. We describe each of these below: o current income tax expense consists solely of regular tax less applicable tax credits, and o deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to accumulated other comprehensive income. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this note) during the year. Investment Tax Credits - ---------------------- We have deferred the investment tax credit associated with our regulated utility business and assets previously held by our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated businesses, other than leveraged leases. Deferred Income Tax Assets and Liabilities - ------------------------------------------ We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes. The tax effects of the differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using income tax rates that are currently in effect. A portion of our total deferred income tax liability relates to our regulated utility business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 6 on page 25. State and Local Taxes - --------------------- As discussed in Note 5 on page 23, tax legislation has made comprehensive changes to the state and local taxation of electric and gas utilities. State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income. Through December 31, 1999, we paid Maryland public service company franchise tax on our utility revenue from sales in Maryland instead of state income tax. We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income. Cash and Cash Equivalents - ------------------------- All highly liquid investments with original maturities of three months or less are considered cash equivalents. At December 31, 2000, $112.5 million of the cash balance included in our Consolidated Balance Sheets was restricted under certain collateral arrangements for our power marketing operation. Inventory - --------- We record our fuel stocks and materials and supplies at the lower of cost or market. We determine cost using the average cost method. 14 Real Estate Projects and Investments - ------------------------------------ In Note 4 on page 22, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments primarily consist of: o approximately 1,600 acres of land holdings in various stages of development located at 11 sites in the central Maryland region, o a 4,500 unit mixed-use planned unit development located in Anne Arundel County, Maryland of which 1,300 residential units and 11 acres for commercial development remain, o an operating waste water treatment plant located in Anne Arundel County, Maryland, and o an equity interest in Corporate Office Properties Trust, a real estate investment trust. The costs incurred to acquire and develop properties are included as part of the cost of the properties. Financial Investments and Trading Securities - -------------------------------------------- In Note 4 on page 22, we summarize the financial investments that are in our Consolidated Balance Sheets. SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities, which we describe separately below. We report investments that are not covered by SFAS No. 115 at their cost. Trading Securities - ------------------ Our other nonregulated businesses classify some of their investments in marketable equity securities and financial limited partnerships as trading securities. We include any unrealized gains or losses on these securities in "Nonregulated revenues" in our Consolidated Statements of Income. Available-for-Sale Securities - ----------------------------- We classify our investments in the nuclear decommissioning trust funds as available-for-sale securities. We describe the nuclear decommissioning trusts and the reserves under the heading "Nuclear Decommissioning" later in this note. In addition, our other nonregulated businesses classify some of their investments in marketable equity securities as available-for-sale securities, including the investment in Orion Power Holdings, Inc. (Orion) effective June 1, 2001. We discuss the accounting for the investment in Orion in more detail in Note 4 on page 22. We include any unrealized gains or losses on our available-for-sale securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. Evaluation of Assets for Impairment and Other Than Temporary Decline in Value - ----------------------------------------------------------------------------- SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, requires us to evaluate certain assets that have long lives (generating property and equipment and real estate) to determine if they are impaired if certain conditions exist. We determine if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We would record an impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset. Additionally, we evaluate our equity-method investments to determine whether they have experienced a loss in value that is considered other than a temporary decline in value. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future market prices and project costs could vary from those used in our impairment evaluations, and the impact of such variations could be material. Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning - ------------------------------------------------------------------------------ We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 121. Our original costs include: o material and labor, o contractor costs, and o construction overhead costs and financing costs (where applicable). We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $150 million at December 31, 2001 and $143 million at December 31, 2000. The "Nonregulated generation property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $1,158.6 million at December 31, 2001 and $908.7 million at December 31, 2000. When we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets that were depreciated under the composite, straight-line method. This includes regulated utility property, plant and equipment and nonregulated generating assets previously owned by the regulated utility. For all other assets, we remove the accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income. The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income as incurred. 15 Depreciation Expense - -------------------- We compute depreciation for our generating, electric transmission and distribution, and gas facilities over the estimated useful lives of depreciable property using either the: o composite, straight-line rates (approved by the Maryland PSC for our regulated utility business) applied to the average investment in classes of depreciable property based on an average rate of approximately three percent per year, or o units of production method. Other assets are depreciated using the straight-line method and the following estimated useful lives: Asset Estimated Useful Lives - ---------------------------------------------------------- Building and improvements 20 - 50 years Transportation equipment 5 - 15 years Office equipment and computer software 3 - 20 years Amortization Expense - -------------------- Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time that approximates the useful life of the related item. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income. An amount is considered fully amortized when it has been reduced to zero. Nuclear Fuel - ------------ We amortize nuclear fuel based on the energy produced over the life of the fuel including the quarterly fees we pay to the Department of Energy for the future disposal of spent nuclear fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Operating expenses" in our Consolidated Statements of Income. Nuclear Decommissioning - ----------------------- We record an expense and a reserve for the costs expected to be incurred in the future to decommission the radioactive portion of Calvert Cliffs based on a sinking fund methodology. The accumulated decommissioning reserve is recorded in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $304.6 million at December 31, 2001 and $275.4 million at December 31, 2000. Our contributions to the nuclear decommissioning trust funds were $22.0 million for 2001, $13.2 million for 2000, and $17.6 million for 1999. Under the Maryland PSC's order deregulating electric generation, BGE's customers must pay a total of $520 million in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs. BGE is collecting this amount on behalf of and passing it to Calvert Cliffs Nuclear Power Plant, Inc. Calvert Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this amount and the actual costs to decommission the plant. We recorded a reserve for the costs expected to be incurred in the future to decommission the radioactive portion of Nine Mile Point under the discounted future cash flows methodology. The total reserve was $224.4 million at December 31, 2001. We have determined that the decommissioning trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the radioactive portions of the plant and as such, no contributions were made to the trust funds during the year ended December 31, 2001. In accordance with Nuclear Regulatory Commission (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission Calvert Cliffs and Nine Mile Point. The assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate. We use the facility-specific cost estimate for funding these costs and providing the required financial assurance. We classify the investments in the nuclear decommissioning trust funds as available-for-sale securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this note. As owners of Calvert Cliffs Nuclear Power Plant, we are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The contributions are generally payable over 15 years with escalation for inflation and are based upon the proportionate amount of uranium enriched by the Department of Energy for each utility. We amortize the deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The previous owners retained the obligation for Nine Mile Point. Capitalized Interest and Allowance for Funds Used During Construction - --------------------------------------------------------------------- Capitalized Interest - -------------------- With the issuance of the Restructuring Order, we ceased accruing AFC (discussed below) for electric generation-related construction projects. Our nonregulated businesses capitalize interest costs under SFAS No. 34, Capitalizing Interest Costs, for costs incurred to finance our power plant construction projects and real estate developed for internal use. Allowance for Funds Used During Construction (AFC) - -------------------------------------------------- We finance regulated utility construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility property is placed in service. The AFC rates are 9.4% for electric plant, 8.6% for gas plant, and 9.2% for common plant. We compound AFC annually. 16 Long-Term Debt - -------------- We defer all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs to expense over the life of the debt. When we incur gains or losses on debt that we retire prior to maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. Use of Accounting Estimates - --------------------------- Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including: o our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, o our disclosure of contingent assets and liabilities at the dates of the financial statements, and o our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates. Reclassifications - ----------------- We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. Accounting Standards Adopted - ---------------------------- On January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. These statements require that we recognize all derivatives on the balance sheet at fair value. Changes in the value of derivatives that are not hedges must be recorded in earnings. We use derivatives in connection with our power marketing and risk management activities and to hedge the risk of variations in future cash flows from forecasted purchases and sales of electricity and gas in our electric generation operations as more fully described in the Risk Management section on page 13. Under SFAS No. 133, changes in the value of derivatives designated as hedges that are effective in offsetting the variability in cash flows of forecasted transactions are recognized in other comprehensive income until the forecasted transactions occur. The ineffective portion of changes in fair value of derivatives used as cash-flow hedges is immediately recognized in earnings. In accordance with the transition provisions of SFAS No. 133, we recorded the following at January 1, 2001: o an $8.5 million after-tax cumulative effect adjustment that increased earnings, and o a $35.5 million after-tax cumulative effect adjustment that reduced other comprehensive income. The cumulative effect adjustment recorded in earnings represents the fair value as of January 1, 2001 of a warrant for 705,900 shares of common stock of Orion. The warrant had an exercise price of $10 per share and was received in conjunction with our investment in Orion. As part of the sale of Orion to Reliant Resources, Inc., we received cash equal to the difference between Reliant's purchase price of $26.80 per share and the exercise price multiplied by the number of shares subject to the warrant. The cumulative effect adjustment recorded in other comprehensive income represents certain forward sales of electricity that we designated as cash-flow hedges of forecasted transactions primarily through our merchant energy business. Recently Issued Accounting Standards - ------------------------------------ In 2001, the FASB issued SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 141 requires all business combinations to be accounted for under the purchase method. Use of the pooling-of-interests method is prohibited for business combinations initiated after June 30, 2001. This statement also establishes criteria for the separate recognition of intangible assets acquired in a business combination. We do not expect the adoption of this statement to have a material impact on our financial results. SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be subject to periodic testing for impairment. This statement is effective for fiscal years beginning after December 15, 2001, with earlier application permitted only in specified circumstances. We do not expect the adoption of this statement to have a material impact on our financial results. SFAS No. 143 provides the accounting requirements for asset retirement obligations associated with tangible long-lived assets. This statement is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. Currently, we are evaluating this statement and have not determined its impact on our financial results, however, it could be material. SFAS No. 144 replaces FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144 addresses financial reporting for the impairment or disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years, with early application encouraged. We do not expect the adoption of this statement to have a material impact on our financial results. However, we expect to reclassify our senior-living facilities business as a discontinued operation in the first quarter of 2002 as required under this standard. 17 Note 2. Contract Termination, Workforce Reduction, and Other Special Costs - -------------------------------------------------------------------------------- 2001 Events - ----------- Pre-Tax After-Tax - ------------------------------------------------------------------- (In millions) Workforce reduction costs: Voluntary termination benefits - VSERP $70.1 $42.5 Settlement and curtailment charges 16.3 9.9 Involuntary severance accrual 19.3 11.7 - ------------------------------------------------------------------- Total workforce reduction costs 105.7 64.1 Contract termination related costs 224.8 139.6 Impairment losses and other costs: Loss on sale of Guatemalan operation 43.3 28.1 Impairments of real estate, senior-living and international investments 107.3 69.7 Cancellation of domestic power projects 46.9 30.5 Reduction of financial investment 4.6 2.8 - ------------------------------------------------------------------- Total impairment losses and other costs 202.1 131.1 - ------------------------------------------------------------------- Total special costs $532.6 $334.8 =================================================================== Workforce Reduction Costs - ------------------------- Voluntary Special Early Retirement Programs - VSERP - --------------------------------------------------- In the fourth quarter of 2001, we undertook several measures to reduce our workforce through both voluntary and involuntary means. The purpose of these programs was to reduce our operating costs to become more competitive. We offered several Voluntary Special Early Retirement Programs (VSERP) to employees of Constellation Energy and certain subsidiaries. The first group of these programs offered enhanced early retirement benefits to employees age 55 or older with 10 or more years of service. The second group of these programs offered enhanced early retirement benefits to employees age 50 to 54 with 20 or more years of service. Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The $70.1 million in the above table reflects the portion of the total cost of that program charged to expense for the 507 employees that elected to participate. BGE recorded $37.9 million of this amount. BGE also recorded $13.7 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6 on page 25. Settlement and Curtailment Charges - ---------------------------------- In connection with the age 55 or older VSERP, a significant number of the participants in our nonqualified pension plans are retiring. As a result, we recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. BGE recorded $6.6 million of this amount. Additional details on the VSERP and their impact on our pension and postretirement benefit plans are discussed in Note 7 on page 26. Involuntary Severance Accrual - ----------------------------- The voluntary programs were designed, offered, and timed to minimize the number of employees who will be involuntarily severed under our overall workforce reduction plan. Our workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied through the age 55 and over VSERP and was specific as to company, organizational unit, and position. However, the number of employees that will elect to voluntarily retire under the age 50 to 54 VSERP and how many will thereafter be involuntarily severed is unknown until after the election period of the VSERP ends in February 2002. In accordance with EITF 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring), the Company recognized a liability of $25.1 million at December 31, 2001 for the targeted number of involuntary terminations that will result if no employees elect the age 50 to 54 VSERP. The $19.3 million in the table above represents involuntary severance charged to expense in 2001 in connection with our workforce reduction programs. BGE recorded $12.5 million of this amount. BGE also recorded $5.8 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6 on page 25. We will record any additional cost in excess of the 2001 involuntary severance accrual for those eligible participants that elect the 50 to 54 VSERP in 2002. Contract Termination Related Costs - ---------------------------------- On October 26, 2001, we announced the decision to remain a single company and canceled prior plans to separate our merchant energy business from our remaining businesses. We also announced the termination of our power business services agreement with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196.7 million to terminate the power business services agreement with our power marketing operation and $159 million previously recognized as a payable for services rendered under the agreement. Goldman Sachs also will not make an equity investment in our merchant energy business as previously announced. In addition, we terminated a software agreement we had whereby Goldman Sachs would provide maintenance, support, and minor upgrades to our risk management and trading system. We recognized $17.6 million in expense in the fourth quarter of 2001 representing the unamortized prepaid costs related to this agreement. Finally, we incurred approximately $10.5 million in employee-related expenses and advisory costs from investment bankers and legal counsel. In total, we recognized expenses of approximately $224.8 million in the fourth quarter of 2001 relating to the termination of our relationship with Goldman Sachs and our decision not to separate. 18 Impairment Losses and Other Costs - --------------------------------- Sale of Guatemalan Operation - ---------------------------- On November 8, 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, LLC, the international business unit of Duke Energy. Through this sale, Duke Energy acquired Grupo Generador de Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts. We decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As a result of this transaction, we are no longer committed to making significant future capital investments in a non-core operation. We recorded a $43.3 million loss on this sale. Impairments of Real Estate, Senior-Living, and Other International Investments - ------------------------------------------------------------------------------ In the fourth quarter of 2001, our other nonregulated businesses recorded $107.3 million in impairments of certain real estate projects, senior-living facilities, and international assets to reflect the fair value of these investments. These investments represent non-core assets with a book value of approximately $140.6 million after these impairments. As part of our focus on capital and cash requirements and on our core energy businesses, the following occurred: o We decided to sell six real estate projects without further development and all of our 18 senior-living facilities in 2002 and accelerate the exit strategies for two other real estate projects that we will continue to hold and own over the next several years. The real estate projects include approximately 1,300 acres of land holdings in various stages of development located in seven sites in the central Maryland region and an operating waste water treatment plant located in Anne Arundel County, Maryland. o We decided to accelerate the exit strategy for our interest in a Panamanian electric distribution company. As a non-core asset, management has decided to reduce the cost and risk of holding this asset indefinitely and intends to dispose of this asset. We believe a sale of this investment can be completed by mid-to-late 2003. o We incurred an other than temporary decline in our equity method investment in the Bolivian Generating Group, which owns an interest in an electric generation concession in Bolivia. This decline in value resulted from a deterioration of our investment's position in the dispatch curve of its capacity market. As a result, we recorded the impairment in accordance with the provisions of Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. The impairments of our real estate, senior-living facilities, and Panama investments were recorded in accordance with the provisions of SFAS No. 121. These impairments resulted from our change from an intent to hold to an intent to sell certain of these non-core assets in 2002, and our decision to limit future costs and risks by accelerating the exit strategies for certain assets that cannot be sold by the end of 2002. Previously, our strategy for these investments was to hold them until we could obtain reasonable value. Under that strategy, the expected cash flows were greater than our investment and no impairment was recognized. Impairment of Domestic Power Projects - ------------------------------------- In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million primarily due to $40.8 million in impairments under SFAS No. 121 associated with the termination of our planned development projects in Texas, California, Florida, and Massachusetts that are not currently under construction. The impairments include amounts paid for the purchase of four turbines related to these development projects. We decided to terminate our development projects due to the expected excess generation capacity in most domestic markets and the significant decline in the forward market prices of electricity. In accordance with the provisions of APB No. 18, we recognized $6.1 million for an other than temporary decline in the value of our investment in a waste burning power plant in Michigan where operating cash flows are not sufficient to pay existing debt service and we are not likely to recover our equity interest in this investment. Reduction of Financial Investment - --------------------------------- Our financial investments business recorded a $4.6 million reduction of its investment in a leased aircraft due to the other than temporary decline in the estimated residual value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry. This investment is accounted for as a leveraged lease under SFAS No. 13, Accounting for Leases. 2000 Events - ----------- In 2000, BGE offered a targeted VSERP to employees ages 55 or older with 10 or more years of service in targeted positions that elected to retire on June 1, 2000 to reduce our operating costs to become more competitive. BGE recorded approximately $10.0 million pre-tax for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. BGE is amortizing this regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC gas base rate order as discussed in Note 6 on page 25. The remaining $7.0 million, or $4.2 million after-tax, related to BGE's electric business and was charged to expense. 19 1999 Events - ----------- Our generation operation recorded a $21.4 million pre-tax, or $14.2 million after-tax, impairment of two geothermal power projects. These impairments occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the inability to restructure certain project agreements. For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production. Our Latin American operation recorded a $7.1 million pre-tax, or $4.5 million after-tax, impairment to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy at that time to focus on our core businesses. Our financial investments operation exchanged its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE) as part of a business combination whereby ACE acquired all of the outstanding capital stock of Capital Re. As a result, our financial investments operation wrote-down its $94.2 million investment in Capital Re stock by $26.2 million pre-tax, or $16.0 million after-tax, to reflect the closing price of the business combination. Our real estate and senior-living facilities operations entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terminated in November 1999. However, our real estate and senior-living operations recorded a $9.6 million pre-tax, or $5.8 million after-tax, impairment related to the proposed sale of these facilities. Note 3. Information by Operating Segment - -------------------------------------------------------------------------------- Our reportable operating segments are - Merchant Energy, Regulated Electric, and Regulated Gas: o Our nonregulated merchant energy business in North America: - provides power marketing, origination transactions, and risk management services, - develops, owns, and operates generating facilities and/or power projects in North America, and - provides nuclear consulting services. o Our regulated electric business purchases, distributes, and sells electricity in Maryland. o Our regulated gas business purchases, transports, and sells natural gas in Maryland. We have restated certain prior-period information for comparative purposes based on our reportable operating segments. Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the merchant energy business segment. Prior to that date, the financial results of electric generation are included in our regulated electric business. Our remaining nonregulated businesses: o provide energy products and services, o sell and service electric and gas appliances, and heating and air conditioning systems, engage in home improvements, and sell electricity and natural gas through mass marketing efforts, o provide cooling services, o engage in financial investments, o develop, own, and manage real estate and senior-living facilities, and o own interests in Latin American power generation and distribution projects and investments. These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown on the next page. 20
Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated ------------- ------------- ------------ --------------- ------------ --------------- (In millions) 2001 Unaffiliated revenues $ 614.3 $2,039.6 $674.3 $600.1 $ -- $3,928.3 Intersegment revenues 1,151.2 0.4 6.4 2.0 (1,160.0) -- - ---------------------------------- ------------- ------------- ------------ --------------- ------------ --------------- Total revenues 1,765.5 2,040.0 680.7 602.1 (1,160.0) 3,928.3 Depreciation and amortization 174.9 173.3 47.7 23.2 -- 419.1 Fixed charges 25.8 135.8 28.5 48.7 -- 238.8 Income tax expense (benefit) 25.2 36.8 25.7 (49.8) -- 37.9 Cumulative effect of change in accounting principle -- -- -- 8.5 -- 8.5 Net income (loss) (a) 93.1 50.9 37.5 (90.6) -- 90.9 Segment assets 8,134.3 3,764.9 1,104.2 1,314.0 (239.8) 14,077.6 Capital expenditures 1,815.0 180.3 58.7 35.0 -- 2,089.0 2000 Unaffiliated revenues $421.1 $2,134.7 $603.8 $692.9 $ -- $3,852.5 Intersegment revenues 604.6 0.5 7.8 20.4 (633.3) -- - ---------------------------------- ------------- ------------- ------------ --------------- ------------ --------------- Total revenues 1,025.7 2,135.2 611.6 713.3 (633.3) 3,852.5 Depreciation and amortization 83.6 319.9 46.2 20.3 -- 470.0 Equity in income of equity-method investees (b) -- 2.4 -- -- -- 2.4 Fixed charges 18.3 168.4 27.3 65.8 (8.4) 271.4 Income tax expense 118.5 72.2 21.9 17.5 -- 230.1 Net income (c) 198.6 102.3 30.6 13.8 -- 345.3 Segment assets 7,295.5 3,392.3 1,089.9 1,491.5 (329.9) 12,939.3 Capital expenditures 699.0 290.3 59.7 131.5 -- 1,180.5 1999 Unaffiliated revenues $277.3 $2,258.8 $ 476.5 $828.3 $ -- $3,840.9 Intersegment revenues -- 1.2 11.6 20.1 (32.9) -- - ---------------------------------- ------------- ------------- ------------ --------------- ------------ --------------- Total revenues 277.3 2,260.0 488.1 848.4 (32.9) 3,840.9 Depreciation and amortization 7.5 376.4 44.9 21.0 -- 449.8 Equity in income of equity-method investees (b) -- 5.1 -- -- -- 5.1 Fixed charges -- 174.2 26.1 56.1 (1.4) 255.0 Income tax expense (benefit) 29.2 149.2 18.1 (10.1) -- 186.4 Extraordinary loss -- 66.3 -- -- -- 66.3 Net income (loss) (d) 52.4 198.8 33.0 (24.1) -- 260.1 Segment assets 1,259.0 6,312.6 915.3 1,239.7 18.5 9,745.1 Capital expenditures 163.0 366.8 69.2 115.2 -- 714.2
(a) Our merchant energy business, our regulated electric business, our regulated gas business, and our other nonregulated businesses recognized $197.9 million, $33.7 million, $0.8 million, and $102.4 million, respectively, for workforce reduction costs, contract termination related costs, and impairment losses and other costs as described more fully in Note 2. (b) Our merchant energy business records its equity in the income of equity method investees in unaffiliated revenues. (c) Our regulated electric business recorded expense of $4.2 million related to employees that elected to participate in a Voluntary Special Early Retirement Program. In addition, our merchant energy business recorded a $15.0 million deregulation transition cost incurred by our power marketing operation. (d) Our regulated electric business recorded expense of $4.9 million related to Hurricane Floyd. Our merchant energy business recorded $14.2 million for the impairment of two geothermal power plants. Our Latin American operation recorded $4.5 million for the impairment to reflect the fair value of our investment in a power project in Bolivia. Our financial investments operation recorded $16.0 million for the reduction of its investment in Capital Re stock to reflect the market value of this investment. Our real estate and senior-living facilities operation recorded $5.8 million for the impairment of certain senior-living facilities. 21 Note 4. Investments - -------------------------------------------------------------------------------- Real Estate Projects and Investments - ------------------------------------ Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following: At December 31, 2001 2000 - ---------------------------------- ------------- ------------- (In millions) Properties under development $100.5 $165.1 Operating properties (net of accumulated depreciation) 0.9 12.7 Equity interest in real estate investments 109.3 112.5 - ---------------------------------- ------------- ------------- Total real estate projects and investments $210.7 $290.3 ================================== ============= ============= See Note 2 on page 18 for a discussion of impairments in 2001. Power Projects - -------------- Investments in power projects held by our merchant energy business consist of the following: At December 31, 2001 2000 - ---------------------------------- ------------- ------------- (In millions) Equity Method $480.3 $488.4 Cost Method 10.7 10.8 - ---------------------------------- ------------- ------------- Total power projects $491.0 $499.2 ================================== ============= ============= Our percentage voting interest in power projects accounted for under the equity method ranges from 16% to 50%. Equity in earnings of these power projects were $24.2 million in 2001, $50.2 million in 2000, and $49.7 million in 1999. Our power projects accounted for under the equity method include investments of $296.4 million in 2001 and $297.9 million in 2000 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 11 on page 36. Our Latin American operation held power projects of $8.1 million at December 31, 2001 and $11.4 million at December 31, 2000. See Note 2 on page 18 for a discussion of impairments recorded in 2001. Orion and Financial Investments - ------------------------------- Financial investments consist of the following: At December 31, 2001 2000 - ---------------------------------- ------------- ------------- (In millions) Orion $442.5 $192.0 Marketable equity securities 20.2 105.9 Financial limited partnerships 25.8 32.7 Leveraged leases 14.7 22.4 - ---------------------------------- ------------- ------------- Total financial investments $503.2 $353.0 ================================== ============= ============= Investments Classified as Available-for-Sale - -------------------------------------------- We classify the following investments as available-for-sale: o nuclear decommissioning trust funds, o our other nonregulated businesses' marketable equity securities (shown above), and o Orion. This means we do not expect to hold them to maturity, and we do not consider them trading securities. Effective June 1, 2001, we changed our accounting for the investment in Orion from the equity method to the cost method. This change resulted from no longer having significant influence as required under equity method accounting due to a reduction in our ownership percentage. Our ownership percentage decreased due to Orion's issuance of 13 million shares of common stock that were sold in a public offering and due to our sale of one million shares as part of the offering. At December 31, 2001, the unrealized gain on our investment in Orion was $244.0 million. In addition, at December 31, 2001, we owned a warrant for 705,900 shares of common stock in Orion with a fair market value of $11.8 million. These warrants are accounted for under SFAS No. 133 as discussed in Note 1 on page 17. We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, in the following tables. We use specific identification to determine cost in computing realized gains and losses, except we use average cost basis for our investment in Orion. At December 31, Amortized Unrealized Unrealized Fair 2001 Cost Basis Gains Losses Value - -------------------- ---------- ---------- ---------- -------- (In millions) Marketable equity securities $773.9 $270.6 $(10.3) $1,034.2 Corporate debt and U.S. Government agency 47.7 1.5 -- 49.2 State municipal bonds 38.4 3.3 (0.2) 41.5 - -------------------- ---------- ---------- ---------- -------- Totals $860.0 $275.4 $(10.5) $1,124.9 ==================== ========== ========== ========== ======== At December 31, Amortized Unrealized Unrealized Fair 2000 Cost Basis Gains Losses Value - -------------------- ----------- ---------- ---------- -------- (In millions) Marketable equity securities $171.8 $68.9 $(2.2) $238.5 Corporate debt and U.S. Government agency 26.1 0.1 (0.1) 26.1 State municipal bonds 61.3 2.3 (0.4) 63.2 - -------------------- ----------- ---------- ---------- -------- Totals $259.2 $71.3 $(2.7) $327.8 ==================== =========== ========== ========== ======== 22 In addition to the above securities, the nuclear decommissioning trust funds included $7.7 million at December 31, 2001 and $6.8 million at December 31, 2000 of cash and cash equivalents. The preceding tables include $21.0 million in 2001 and $34.7 million in 2000 of unrealized net gains associated with the nuclear decommissioning trust funds that are reflected as a change in the nuclear decommissioning trust funds on the Consolidated Balance Sheets. Gross and net realized gains and losses on available-for-sale securities were as follows: 2001 2000 1999 - ---------------------------- --------- --------- --------- (In millions) Gross realized gains $47.6 $54.5 $ 11.7 Gross realized losses (7.9) (8.0) (38.8) - ---------------------------- --------- --------- --------- Net realized gains (losses) $39.7 $46.5 $(27.1) ============================ ========= ========= ========= The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule: At December 31, 2001 Amount - ------------------------------------ ------------------------- (In millions) Less than 1 year $ 8.4 1-5 years 34.3 5-10 years 22.2 More than 10 years 25.8 - ------------------------------------ ------------------------- Total maturities of debt securities $90.7 ==================================== ========================= Note 5. Rate Matters and Accounting Impacts of Deregulation - -------------------------------------------------------------------------------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Effective January 1, 2000, the Maryland public service franchise tax was altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise tax on electric and natural gas utilities continues to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results are subject to the Maryland corporate income tax. Beginning July 1, 2000, the tax legislation also provided for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are: o All customers, except a few commercial and industrial companies that have signed contracts with BGE, can choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. o BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006. o Commercial and industrial customers have up to four service options that will fix electric energy rates and transition charges for a period that ends in 2004 to 2006. o BGE's electric fuel rate clause was discontinued effective July 1, 2000. o Electric delivery service rates are frozen through June 2004 for commercial and industrial customers. The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers. o BGE collects $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on its customers' bills. Residential customers will pay this charge through 2006. Commercial and industrial customers will pay in a lump sum or over a period ending in 2004 to 2006, depending on the service option selected by each customer. o Generation-related regulatory assets and nuclear decommissioning costs are included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their amortization schedules prior to July 1, 2000. 23 o Effective July 1, 2000, BGE unbundled rates to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes. o Effective July 1, 2000, BGE transferred, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. o BGE reduced its generation assets by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to mitigate a portion of BGE's potentially stranded investments. o Universal service is being provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually. As discussed in Note 1 on page 11, EITF 97-4 requires that a company should cease applying SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business. SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities. The Restructuring Order provided for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business. We discuss this further in Note 6 on page 25. Pursuant to SFAS No. 101, the book value of property, plant, and equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process we used in evaluating and measuring impairment under the provisions of SFAS No. 121 involved two steps. First, we compared the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant was considered impaired when its undiscounted future net operating cash flows were less than its net book value. Second, we computed the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment. To the extent that the net book value of each impaired electric generation plant exceeded its fair value, we reduced its book value. Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with the Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher than its estimated fair value. However, Calvert Cliffs was not considered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceeded its book value. Accordingly, BGE did not record any impairment related to Calvert Cliffs. However, BGE recognized after-tax impairment losses totaling $115.8 million associated with certain of its fossil plants under the provisions of SFAS No. 121. BGE had contracts to purchase electric capacity and energy that became uneconomic upon the deregulation of electric generation. Therefore, BGE recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts. In addition, BGE had deferred certain energy conservation expenditures that would not be recovered through its transmission and distribution business under the Restructuring Order. Accordingly, BGE recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures. At December 31, 1999, the total charge for BGE's electric generating plants that were impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately $160.3 million after-tax. BGE recorded approximately $94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately $56.0 million of associated deferred income taxes. The regulatory asset was amortized as it was recovered from ratepayers through June 30, 2000. This accomplished the $150 million reduction of its generation plants required by the Restructuring Order. BGE recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that was not recovered under the Restructuring Order. 24 Note 6. Regulatory Assets (net) - -------------------------------------------------------------------------------- As discussed in Note 1 on page 11, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers. We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below. At December 31, 2001 2000 - -------------------------------------- ---------- ---------- (In millions) Electric generation-related regulatory asset $249.0 $267.8 Income taxes recoverable through future rates (net) 95.6 101.2 Deferred postretirement and postemployment benefit costs 35.5 38.7 Deferred environmental costs 26.0 28.8 Deferred fuel costs (net) 33.5 71.1 Workforce reduction costs 21.6 2.8 Other (net) 2.6 4.5 - -------------------------------------- ---------- ---------- Total regulatory assets (net) $463.8 $514.9 ====================================== ========== ========== Electric Generation-Related Regulatory Asset - -------------------------------------------- With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business. In accordance with SFAS No. 101 and EITF 97-4, all individual generation-related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business. Pursuant to the Restructuring Order, BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, new generation-related regulatory asset for amounts to be collected through its regulated transmission and distribution business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. Income Taxes Recoverable Through Future Rates (net) - --------------------------------------------------- As described in Note 1 on page 14, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse. Deferred Postretirement and Postemployment Benefit Costs - -------------------------------------------------------- Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for post-retirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 7 on page 26. Deferred Environmental Costs - ---------------------------- Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 11 on page 34. We are amortizing $21.6 million of these costs (the amount we had incurred through October 1995) and $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. Deferred Fuel Costs - ------------------- As described in Note 1 on page 12, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas, and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers. We show our deferred fuel costs in the following table. At December 31, 2001 2000 - -------------------------------------- ---------- ---------- (In millions) Electric $ -- $42.3 Gas 33.5 28.8 - -------------------------------------- ---------- ---------- Deferred fuel costs (net) $33.5 $71.1 ====================================== ========== ========== Under the terms of the Restructuring Order, BGE's electric fuel rate clause was discontinued effective July 1, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We collected this accumulated difference from customers over the twelve-month period ending October 2001. Workforce Reduction Costs - ------------------------- The portions of the workforce reduction costs associated with the VSERP and involuntary severance programs we announced in 2001 and 2000 that relate to BGE's gas business are deferred as regulatory assets in accordance with the Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year periods. See Note 2 on page 18 and Note 7 on page 26. 25 Note 7. Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits - -------------------------------------------------------------------------------- We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below. Nine Mile Point offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits for Nine Mile Point are included in the tables beginning on the next page. Pension Benefits - ---------------- We sponsor several defined benefit pension plans for our employees. These include the basic, qualified plan that most employees participate in and several nonqualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay. Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees. We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2001 were mostly marketable equity and fixed income securities. In 1999, we made the following amendments: o eligible participants were allowed to choose between an enhanced version of the current benefit formula and a new pension equity plan (PEP) formula. Pension benefits for eligible employees hired after December 31, 1999 are based on a PEP formula, and o pension and survivor benefits were increased for participants who retired prior to January 1, 1994 and for their surviving spouses. The financial impacts of the amendments are included in the tables beginning on the next page. Postretirement Benefits - ----------------------- We sponsor defined benefit postretirement health care and life insurance plans that cover substantially all of our employees. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused: o a transition obligation, which we are amortizing over 20 years, and o an increase in annual postretirement benefit costs. For our nonregulated businesses, we expense all postretirement benefit costs. For our regulated utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders: o in an April 1993 rate order, the Maryland PSC allowed us to expense one-half and defer, as a regulatory asset (see Note 6 on page 25), the other half of the increase in annual postretirement benefit costs related to our regulated electric and gas businesses, and o in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our regulated gas business. Beginning in 1998, the Maryland PSC authorized us to: o expense all of the increase in annual postretirement benefit costs related to our regulated electric business, and o amortize the regulatory asset for postretirement benefit costs related to our regulated electric and gas businesses over 15 years. VSERP - ----- In 2001, our Board of Directors approved several voluntary retirement programs for Constellation Energy and certain subsidiaries. The first group of these programs offered enhanced early retirement benefits to employees age 55 or older with 10 or more years of service. The second group of these programs offered enhanced early retirement benefits to employees age 50 to 54 with 20 or more years of service. Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The total cost of that program was approximately $83.8 million ($63.5 million in pension termination benefits, $18.5 million in postretirement benefit costs, and $1.8 million in education and outplacement assistance costs). Of this amount, BGE recorded approximately $13.7 million on its balance sheet as a regulatory asset of its gas business. This amount will be amortized over a 5-year period as provided for in prior Maryland PSC rate orders. In connection with the retirement of a significant number of the participants in the nonqualified pension plans we recognized a settlement loss of approximately $10.5 million 26 and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88. Since the age 50 to 54 programs allow employees to make their elections beginning in January through February 2002, the cost of that program will be reflected in 2002. We recorded a $133.0 million additional minimum pension liability adjustment as a result of the combination of decreases in the fair value of plan assets due to a declining equity market in 2001 and an increased pension liability primarily due to the VSERP. We charged $59.0 million of this adjustment to an intangible asset and included in "Other deferred charges" in our Consolidated Balance Sheets. The remaining $74.0 million, or $44.7 million after-tax, of this adjustment was included in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. In 2000, we offered a targeted VSERP to provide enhanced early retirement benefits to certain eligible participants in targeted jobs at BGE that elected to retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6 million for pension termination benefits and $2.4 million for postretirement benefit costs) for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. We amortize this regulatory asset over a 5-year period. The remaining $7.0 million related to BGE's electric business was charged to expense. The cost of the 2001 and 2000 voluntary retirement programs and the settlement or curtailment losses are not included in the tables of net periodic pension and postretirement benefit costs. Obligations, Assets, and Funded Status - -------------------------------------- We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans including the effect of the Nine Mile Point acquisition, in the following tables. Pension Postretirement Benefits Benefits 2001 2000 2001 2000 - -------------------------- -------- --------- ------- -------- (In millions) Change in benefit obligation - ---------------------------- Benefit obligation at January 1 $1,045.1 $1,016.7 $375.9 $358.7 Service cost 25.8 25.4 8.4 7.7 Interest cost 76.1 73.1 29.2 26.6 Plan participants' contributions -- -- 3.0 2.8 Actuarial loss 42.6 0.8 49.1 40.9 Plan amendments -- 6.7 -- (41.1) VSERP charge 63.5 7.6 18.5 2.4 Curtailment 9.7 -- -- -- Settlement (23.0) -- -- -- Nine Mile Point acquisition 91.8 -- 15.0 -- Benefits paid (72.4) (85.2) (23.9) (22.1) - ------------------------- --------- --------- ------- -------- Benefit obligation at December 31 $1,259.2 $1,045.1 $475.2 $375.9 ========================= ========= ========= ======= ======== Pension Postretirement Benefits Benefits 2001 2000 2001 2000 - -------------------------- --------- -------- ------- -------- (In millions) Change in plan assets - --------------------- Fair value of plan assets at January 1 $1,030.1 $1,084.9 $ -- $ -- Actual return on plan assets (42.7) 3.7 -- -- Employer contribution 39.4 26.7 20.9 19.3 Plan participants' contributions -- -- 3.0 2.8 Benefits paid (72.4) (85.2) (23.9) (22.1) - -------------------------- --------- -------- ------- -------- Fair value of plan assets at December 31 $ 954.4 $1,030.1 $ -- $ -- ========================== ========= ======== ======= ======== Pension Postretirement Benefits Benefits 2001 2000 2001 2000 - ------------------------- ---------- -------- -------- --------- (In millions) Funded Status - ------------- Funded Status at December 31 $(304.8) $(15.0) $(475.2) $(375.9) Unrecognized net actuarial loss 207.8 49.2 107.8 61.4 Unrecognized prior service cost 56.7 59.2 (0.4) (0.4) Unrecognized transition obligation -- -- 86.9 94.8 Unamortized net asset from adoption of SFAS No. 87 -- (0.2) -- -- Pension liability adjustment (133.0) -- -- -- - ------------------------- ---------- -------- -------- --------- (Accrued) prepaid benefit cost $(173.3) $ 93.2 $(280.9) $(220.1) ========================= ========== ======== ======== ========= 27 Net Periodic Benefit Cost - ------------------------- We show the components of net periodic pension benefit cost in the following table: Year Ended December 31, 2001 2000 1999 - -------------------------------- --------- -------- ---------- (In millions) Components of net periodic - -------------------------- pension benefit cost -------------------- Service cost $25.8 $25.4 $26.1 Interest cost 76.1 73.1 65.3 Expected return on plan assets (87.5) (83.6) (76.6) Amortization of transition obligation (0.2) (0.2) (0.2) Amortization of prior service cost 6.5 6.5 2.5 Recognized net actuarial loss 2.8 2.6 10.1 Amount capitalized as construction cost (2.5) (3.4) (4.2) - -------------------------------- --------- -------- ---------- Net periodic pension benefit cost $21.0 $20.4 $23.0 ================================ ========= ======== ========== We show the components of net periodic postretirement benefit cost in the following table: Year Ended December 31, 2001 2000 1999 - -------------------------------- --------- -------- ---------- (In millions) Components of net periodic - -------------------------- postretirement benefit cost --------------------------- Service cost $ 8.4 $ 7.7 $ 8.6 Interest cost 29.2 26.6 24.4 Amortization of transition obligation 7.9 7.9 11.0 Recognized net actuarial loss 3.3 3.1 1.9 Amount capitalized as construction cost (14.5) (10.8) (9.4) - -------------------------------- --------- -------- ---------- Net periodic postretirement benefit cost $34.3 $34.5 $36.5 ================================ ========= ======== ========== Assumptions - ----------- We made the assumptions below to calculate our pension and postretirement benefit obligations. Pension Postretirement Benefits Benefits At December 31, 2001 2000 2001 2000 - ------------------------ ------- -------- -------- --------- Discount rate 7.25% 7.50% 7.25% 7.50% Expected return on plan assets 9.00 9.00 N/A N/A Rate of compensation increase 4.00 4.00 4.00 4.00 We assumed the health care inflation rates to be: o in 2001, 5.7% for Medicare-eligible retirees and 9.5% for retirees not covered by Medicare, and o in 2002, 11.0% for both Medicare-eligible retirees and retirees not covered by Medicare. After 2002, we assumed inflation rates will decrease to 7.0% in 2003, 6.5% in 2004, 6.0% in 2005, and 5.5% annually after 2005. A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $63.8 million as of December 31, 2001 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.9 million annually. A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $51.1 million as of December 31, 2001 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.7 million annually. Other Postemployment Benefits - ----------------------------- We provide the following postemployment benefits: o health and life insurance benefits to eligible employees who are found to be disabled under our Disability Insurance Plan, and o income replacement payments for employees found to be disabled before November 1995 (payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees). The liability for these benefits totaled $48.7 million as of December 31, 2001 and $46.7 million as of December 31, 2000. Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 6 on page 25), the postemployment benefit liability attributable to our regulated utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note). We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our regulated electric and gas base rates to recover the higher costs in 1998. We assumed the discount rate for other postemployment benefits to be 5.0% in 2001 and 5.5% in 2000. Employee Savings Plan Benefits - ------------------------------ We, along with several of our subsidiaries, sponsor defined contribution savings plans that are offered to all eligible employees of Constellation Energy and certain employees of our subsidiaries. The Savings Plans are qualified 401(k) plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were: o $12.2 million in 2001, o $10.8 million in 2000, and o $10.4 million in 1999. 28 Note 8. Short-Term Borrowings - -------------------------------------------------------------------------------- Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates. Constellation Energy - -------------------- In anticipation of separating our merchant energy business from our other businesses and to fund working capital requirements and capital expenditures, in June 2001, Constellation Energy arranged a $2.5 billion, 364-day revolving credit facility. However, since we canceled prior plans to separate, we used this facility primarily to fund capital expenditures, and working capital requirements, including commercial paper support, for the merchant energy business. In June 2001, Constellation Energy also arranged a $380 million, 364-day revolving credit facility to be used primarily to support letters of credit and for other short-term financing needs, including commercial paper support. Constellation Energy also has an existing $188.5 million, multi-year revolving credit facility available for short-term and long-term needs, including support for the issuance of letters of credit. Constellation Energy had committed bank lines of credit as described above of $3.1 billion at December 31, 2001 and $565.0 million at December 31, 2000 for short-term financial needs, including support for the issuance of letters of credit. These agreements also support Constellation Energy's commercial paper program. Letters of credit issued under all of our facilities totaled $245.8 million at December 31, 2001 and $297.2 million at December 31, 2000. Constellation Energy had commercial paper outstanding of $954.9 million at December 31, 2001 and $198.7 million at December 31, 2000. The weighted-average effective interest rates for Constellation Energy's commercial paper were 3.73% for the year ended December 31, 2001 and 6.31% for 2000. BGE - --- BGE had no commercial paper outstanding at December 31, 2001 and $32.1 million at December 31, 2000. At December 31, 2001, BGE had unused committed bank lines of credit totaling $243.0 million supporting the commercial paper program compared to $218.0 million at December 31, 2000. BGE has a $25 million revolving credit agreement that is available through 2003. At December 31, 2001 and 2000, BGE did not have any borrowings under the revolving credit agreement. This agreement also supports BGE's commercial paper program. The weighted-average effective interest rates for BGE's commercial paper were 2.53% for the year ended December 31, 2001 and 6.36% for 2000. Other Nonregulated Businesses - ----------------------------- Our other nonregulated businesses had short-term borrowings outstanding of $20.1 million at December 31, 2001 and $12.8 million at December 31, 2000. The weighted-average effective interest rates for our other nonregulated businesses' short-term borrowings were 4.20% for the year ended December 31, 2001 and 8.59% for 2000. Note 9. Long-Term Debt - -------------------------------------------------------------------------------- Long-term debt matures in one year or more from the date of issuance. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements. Constellation Energy - -------------------- On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002. On April 11, 2001, we issued $235.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002. In 2001, we redeemed several Notes that totaled $700.0 million prior to their maturity for a purchase price equal to 100% of their principal amount, plus accrued interest. BGE - --- BGE's First Refunding Mortgage Bonds - ------------------------------------ BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption: o 7 1/4% Series, due 2002 o 5 1/2% Series, due 2004 o 6 1/2% Series, due 2003 o 7 1/2% Series, due 2007 o 6 1/8% Series, due 2003 o 6 5/8% Series, due 2008 29 Holders of the Remarketed Floating Rate Series due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1. BGE's Other Long-Term Debt - -------------------------- On May 11, 2001, BGE issued $200.0 million of Floating Rate Reset Notes that matured on February 5, 2002. Also on May 11, 2001, BGE redeemed $200.0 million of Floating Rate Notes. On December 11, 2001, BGE issued $300.0 million 5.25% Notes, due December 15, 2006. On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred assets. At December 31, 2001, BGE remains contingently liable for the $276.5 million outstanding balance of this debt. On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option for the underwriters to remarket the ROARS on December 15, 2002. If the underwriters do not elect to remarket the ROARS on that date, then BGE must redeem the ROARS at 100% of the principal amount on December 15, 2002. We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2001 in the following table. Weighted-Average Maturity Series Interest Rate Dates - ------------------- ---------------------- ----------------- B 8.77% 2002-2006 C 7.97 2003 D 6.67 2004-2006 E 6.66 2006-2012 G 6.08 2008 Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options. Series E Notes Principal Put Option Dates - ------------------------ -------------- -------------------- (In millions) 6.75%, due 2012 $60.0 June 2002 and 2007 6.75%, due 2012 $25.0 June 2004 and 2007 6.73%, due 2012 $25.0 June 2004 and 2007 BGE Obligated Mandatorily Redeemable Trust Preferred Securities - --------------------------------------------------------------- On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%. The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur. The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest expense" in the Consolidated Statements of Income and is deductible for income tax purposes. BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement. The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power. For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock. Other Nonregulated Businesses - ----------------------------- Revolving Credit Agreement - -------------------------- ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2002. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. Under this agreement, ComfortLink had outstanding $46.0 million at December 31, 2001 and $34.0 million at December 31, 2000. On December 18, 2001, ComfortLink entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option. Mortgage and Construction Loans - ------------------------------- Our nonregulated businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments: o 4.25%, due in 2009 o 9.65%, due in 2028 o 8.00%, due in 2033 The variable rate mortgage notes and construction loans require periodic payment of principal and interest. 30 Maturities of Long-Term Debt - ---------------------------- All of our long-term borrowings mature on the following schedule (includes sinking fund requirements): Constellation Nonregulated Year Energy Business BGE - ----------------------- -------------- ------------- ---------- (In millions) 2002 $635.0 $ 85.4 $ 519.8 2003 -- 86.1 285.6 2004 -- 83.7 155.4 2005 300.0 78.4 46.9 2006 -- 78.4 464.9 Thereafter -- 357.1 947.7 - ----------------------- -------------- ------------- ---------- Total long-term debt at December 31, 2001 $935.0 $769.1 $2,420.3 ======================= ============== ============= ========== At December 31, 2001, BGE had long-term loans totaling $221.5 million that mature after 2002 (including $110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") which contain certain put options under which lenders could potentially require us to repay the debt prior to maturity. Of this amount, $171.5 million could be repaid in 2002 and $50.0 million in 2004. At December 31, 2001, $146.5 million is classified as current portion of long-term debt as a result of these provisions. At December 31, 2001, our other nonregulated businesses had long-term loans totaling $20.0 million that mature after 2003 that lenders could potentially require us to repay early. This amount is classified as current portion of long-term debt as a result of these repayment provisions. Weighted-Average Interest Rates for Variable Rate Debt - ------------------------------------------------------ Our weighted-average interest rates for variable rate debt were: Year ended December 31, 2001 2000 - ------------------------------------------ -------- -------- Nonregulated Businesses - ----------------------- (including Constellation Energy) -------------------------------- Floating rate notes 4.95% 6.98% Loans under credit agreements 4.60 6.64 Mortgage and construction loans 4.39 7.78 Tax-exempt debt transferred from BGE 3.12 4.26 Other tax-exempt debt 1.75 -- BGE - --- Remarketed floating rate series mortgage bonds 4.49% 6.59% Floating rate reset notes 4.14 7.27 Medium-term notes, Series G -- 6.58 Medium-term notes, Series H -- 6.58 Note 10. Leases - -------------------------------------------------------------------------------- There are two types of leases--operating and capital. Capital leases qualify as sales or purchases of property and are reported in the Consolidated Balance Sheets. Capital leases are not material in amount. All other leases are operating leases and are reported in the Consolidated Statements of Income. We expense all lease payments associated with our regulated utility operations. We present information about our operating leases below. Outgoing Lease Payments - ----------------------- We, as lessee, lease some facilities and equipment. The lease agreements expire on various dates and have various renewal options. Lease expense was: o $11.7 million in 2001, o $11.3 million in 2000, and o $12.2 million in 1999. At December 31, 2001, we owed future minimum payments for long-term, noncancelable, operating leases as follows: Year - ------------------------------------------------ ------------- (In millions) 2002 $ 9.1 2003 24.1 2004 39.2 2005 37.9 2006 13.3 Thereafter 145.8 - ------------------------------------------------ ------------- Total future minimum lease payments $269.4 ================================================ ============= The above table includes the operating lease payments for the High Desert project in California through 2006. We are currently leasing and supervising the construction of the High Desert project, a 750 megawatt generating facility in California. The High Desert project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that qualifies as an operating lease. The project is scheduled for completion in the summer of 2003. Under the terms of the lease, we are required to make payments that represent all or a portion of the lease balance if one of the following events occurs: termination of construction prior to completion or our default under the lease. In addition, we may be required to either post cash collateral equal to the outstanding lease balance or we may elect to purchase the property for the outstanding lease balance. At any time during the term of the lease we have the right to pay off the lease and acquire the asset from the lessor. At December 31, 2001, the outstanding lease balance plus other committed expenses was $271.2 million. At the conclusion of the lease term in 2006, we have the following options: o renew the lease upon approval of the lessors, o elect to purchase the property for a price equal to the lease balance at the end of the term, or o request the lessor to sell the property. If we request the lessor to sell the property, we guarantee the sale proceeds up to approximately 83% of the lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based on the ultimate cost of construction and interest incurred during the construction period. 31 Note 11. Commitments, Guarantees, and Contingencies - -------------------------------------------------------------------------------- Commitments - ----------- We have made substantial commitments in connection with our merchant energy, regulated gas, and other nonregulated business. These commitments relate to: o purchase of electric generating capacity and energy, o procurement and delivery of fuels, and o capital for construction programs and loans. Our merchant energy business has a long-term contract for the purchase of electric generating capacity and energy that expires in 2013. Portions of this contract became uneconomical upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining term of the contract as discussed in Note 5 on page 24. At December 31, 2001, the accrued portion of this contract was $10.6 million. Our merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2002 and 2006. In addition, our merchant energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2002 and 2021. Our merchant energy business also has committed to contribute additional capital for our construction program and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest. At December 31, 2001, we estimate the future obligations of our merchant energy business in the following table:
2002 2003 2004 2005 2006 Thereafter Total ------------------------- ----------- ---------- ---------- ---------- ---------- ------------- ----------- (In millions) Purchased capacity and energy $ 16.4 $ 16.0 $ 15.5 $15.1 $15.0 $ 98.5 $ 176.5 Fuel and transportation 318.1 228.3 99.5 49.1 48.8 17.7 761.5 Capital and loans 81.5 0.8 -- -- -- -- 82.3 ------------------------- ----------- ---------- ---------- ---------- ---------- ------------- ----------- Total future obligations $416.0 $245.1 $115.0 $64.2 $63.8 $116.2 $1,020.3 ========================= =========== ========== ========== ========== ========== ============= ===========
Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. These contracts are recoverable under BGE's gas cost adjustment clause discussed in Note 1 on page 12. BGE Home Products & Services has gas purchase commitments of $35.0 million in 2002 and $2.2 million in 2003 related to its gas program. Sale of Receivables - ------------------- BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $25 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against these entities. BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 2001, BGE had sold $8.1 million and BGE Home Products & Services had sold $42.5 million of receivables under these agreements. Guarantees - ---------- At December 31, 2001, Constellation Energy issued guarantees in an amount up to $1,682.4 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries, including $600 million relating to the High Desert project. The actual subsidiary liabilities related to these guarantees totaled $369.9 million at December 31, 2001. At December 31, 2001, Constellation Nuclear guaranteed the $388.1 million sellers' note that financed the acquisition of Nine Mile Point. This guarantee contains covenant provisions that require Constellation Nuclear to maintain a net worth of at least $500 million and a ratio of current assets to current liabilities of at least 1.1. At December 31, 2001, our merchant energy business had other guaranteed outstanding loans and letters of credit of certain power projects totaling $26.7 million. At December 31, 2001, our other nonregulated businesses had guaranteed outstanding loans and letters of credit of real estate projects totaling $15.9 million. BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation. At December 31, 2001, Safe Harbor Water Power Corporation had outstanding debt of $20 million. The maximum amount of BGE's guarantee is $13.3 million. Additionally at December 31, 2001, BGE guaranteed the TOPrS of $250.0 million as discussed in Note 9 on page 30. We assess the risk of loss from these guarantees to be minimal. 32 Environmental Matters - --------------------- We are subject to regulation by various federal, state and local authorities with regard to: o air quality, o water quality, o chemical and waste management and disposal, and o other environmental matters. The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating, transmission, and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of siting and developing, to the ongoing operation of existing or new electric generating, transmission, and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected, and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling, and noise impacts. Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation, as required. We discuss the significant matters below. Clean Air Act - ------------- The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws require significant reductions in SO2 (sulfur dioxide) and NOx (nitrogen oxide) emissions that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology. Certain of these provisions are described in more detail below. Since our generation portfolio is diverse, both in the mix of fuels used to generate electricity, as well as in the age of various facilities, the Clean Air Act requirements have different impacts in terms of compliance costs for each of our projects. Many of these compliance costs may be substantial, as described in more detail below. In addition, the Clean Air Act contains many enforcement tools, ranging from broad investigatory powers to civil, criminal, and administrative penalties and citizen suits. These enforcement provisions also include enhanced monitoring, recordkeeping, and reporting requirements for both existing and new facilities. The Clean Air Act creates a marketable commodity called an SO2 "allowance." All non-exempt facilities over 25 megawatts that emit SO2 must obtain allowances in order to operate after 1999. Each allowance gives the owner the right to emit one ton of SO2. All non-exempt existing facilities have been allocated allowances based on a facility's past production and the statutory emission reduction goals. If additional allowances are needed for new facilities, they can be purchased from facilities having excess allowances or from S02 allowance banks. Our projects comply with the S02 allowance caps through the purchase of allowances, use of emission control devices, or by qualifying for exemptions. We believe that the additional costs of obtaining allowances needed for future generation projects should not materially affect our ability to build, acquire, and operate them. The Clean Air Act also requires states to impose annual operating permit fees. These fees are based on the tons of pollutants emitted from a generating facility and vary based on the type of facility. For example, fees will typically be greater for coal-fired plants than for natural gas fired plants. Our portfolio includes coal-fired plants and gas fired plants, as well as plants using renewable energy sources such as solar and geothermal, which have far less emissions. The fees do not significantly increase our costs. The Ozone Transport Assessment Group, composed of state and local air regulatory officials from the 37 Mid-Western and Eastern states, has recommended additional NOx emission reductions that go beyond current federal standards. These recommendations include reductions from utility and industrial boilers during the summer ozone season. As a result of the Ozone Transport Assessment Group's recommendations, on October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NOx ( a precursor of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOx emission budget for each state, including Maryland and Pennsylvania. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 30, 2004. Coal-fired power plants are a principal target of NOx reductions under this initiative, however, some of our newer coal fired plants may already meet the EPA expectations and will not require the same amount of capital expenditures. Many of the generation facilities are subject to NOx reduction requirements under the EPA rule including those located in Maryland and Pennsylvania. This regulation affects both new and existing facilities causing additional capital investment. At the Brandon Shores facility we have installed, and at our Wagner facility we are installing emission reduction equipment by May 2002, in order to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions reduction equipment by 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate that the equipment needed at these plants will cost approximately $290 million. Through December 31, 2001, we have spent approximately $200 million. 33 Over the past two years, the EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, using its broad investigatory powers, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA and are waiting to see if the EPA takes any further action. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and/or planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities. The Clean Air Act requires the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA has decided to control mercury emissions from coal-fired plants. Compliance could be required by approximately 2007. Final regulations are expected to be issued in 2004 and would affect all coal-fired boilers. The cost of compliance could be material. Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has not yet been ratified by the U.S. Senate. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol on us are unknown at this time. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Fossil fuel-fired power plants, however, are significant sources of carbon dioxide emissions, a principal greenhouse gas. Therefore, our compliance costs with any mandated federal greenhouse gas reductions in the future could be significant. Waste Disposal - -------------- The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA. Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the Maryland Department of the Environment (MDE) that required us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million. We discuss this further in Note 6 on page 25. Through December 31, 2001, we have spent approximately $37 million for remediation at this site. We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results. Litigation - ---------- In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below. California - ---------- Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other defendants (including Constellation Power Development, Inc., a subsidiary of Constellation Power, Inc.) - This class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action seeks damages of $43 billion, recession and reformation of approximately 38 long-term power purchase contracts, and an injunction against improper spending by the state of California. Constellation Power Development, Inc. is named as a defendant but does not have a power purchase agreement with the State of California. However, our High Desert Power Project does have a power purchase agreement with the California Department of Water Resources. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our financial results. 34 Employment Discrimination - ------------------------- Miller, et. al v. Baltimore Gas and Electric Company, et al.--This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the plaintiffs seek back and front pay, along with compensatory and punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit for the beginning of 2003. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our, or BGE's, financial results. Asbestos - -------- Since 1993, BGE has been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. The first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 545 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include: o the identity of BGE's facilities at which the plaintiffs allegedly worked as contractors, o the names of the plaintiff's employers, and o the date on which the exposure allegedly occurred. To date, 36 of these cases were settled for amounts that were not significant. The second type is claims by one manufacturer--Pittsburgh Corning Corp. (PCC)--against BGE and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy, and BGE does not expect PCC to prosecute these claims. These claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about 375 cases have been resolved, all without any payment by BGE. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts we do not know include: o the identity of BGE facilities containing asbestos manufactured by the manufacturer, o the relationship (if any) of each of the individual plaintiffs to BGE, o the settlement amounts for any individual plaintiffs who are shown to have had a relationship to BGE, and o the dates on which/places at which the exposure allegedly occurred. Until the relevant facts for both types of claims are determined, BGE is unable to estimate what its liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, its potential liability could be material. Asset Transfer Order - -------------------- On July 6, 2000, the Mid-Atlantic Power Supply Association (MAPSA) and Shell Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's generation assets issued on June 19, 2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing on the petition on August 23, 2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We also believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results. Restructuring Order - ------------------- In early December 1999, MAPSA, Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to delay implementation of the Restructuring Order, pending a decision on the merits of the appeals by the court. On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of standing (the right of a party to bring a lawsuit to court) and denied its motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals. MAPSA subsequently filed several appeals with the Maryland Court of Special Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court. The effect of the appeals was to delay the implementation of customer choice in BGE's service territory. However, on August 4, 2000, the delay was rescinded and BGE retroactively adjusted its rates as if customer choice had been implemented July 1, 2000. On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results. 35 Nuclear Insurance - ----------------- We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in four program areas: liability, worker radiation claims, property, and accidental outage. However, these policies have certain industry standard exclusions, such as ordinary wear and tear, and war. Terrorist acts, while not excluded from the property and accidental outage policies, are covered as a common occurrence, meaning that if terrorist acts occur against one or more commercial nuclear power plants insured by our insurance company within a 12 month period, they will be treated as one event and the owners of the plants will share one full limit of each type of policy (currently $3.24 billion). Claims that arise out of terrorist acts are also covered by our nuclear liability and worker radiation policies. However, these policies are subject to one industry aggregate limit (currently $200 million) for the risk of terrorism. Unlike the property and accidental outage policies, however, an industry-wide retrospective assessment program applies above the industry limit (see below for explanation of this program). If there were an accident or an extended outage at any unit of Calvert Cliffs or Nine Mile Point, it could have a substantial adverse financial effect on us. Liability Insurance - ------------------- Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of approximately $9.5 billion. We have purchased the maximum available commercial insurance of $200 million, and the remaining $9.3 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $352.4 million per incident, payable at no more than $40 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims. Some of the provisions of this Act expire in August 2002, and the Act is subject to change if those provisions are extended. While we expect these provisions to be extended, we do not know what impact any changes to the Act may have on us. Worker Radiation Claims Insurance - --------------------------------- We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe the old and new policies below: o Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy. o All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with our share being up to $6.3 million. The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority, which continues to own 18 percent of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premiums assessments. If claims under these polices exceed the coverage limits, the provisions of the Price-Anderson Act would apply. Property Insurance - ------------------ Our policies provide $500 million in primary and an additional $2.25 billion in excess coverage for property damage, decontamination, and premature decommissioning liability for Calvert Cliffs or Nine Mile Point. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $56.2 million. Accidental Outage Insurance - --------------------------- Our policies provide indemnification on a weekly basis resulting from an accidental outage of a nuclear unit. Initial coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs, $335.4 million for Unit 1 of Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5 million for Nine Mile Point if an outage at either plant is caused by a single insured physical damage loss. California Power Purchase Agreements - ------------------------------------ Our merchant energy business has $296.4 million invested in operating power projects of which our ownership percentage represents 142 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements. Our merchant energy business was not paid in full for its sales from these plants to the two utilities from November 2000 through early April 2001. At December 31, 2001, our portion of the amount due for unpaid power sales from these utilities was approximately $45 million. We recorded reserves of approximately 20% of this amount. 36 These projects entered into agreements with PGE and SCE that provide for five-year fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. These agreements also provide for the payment of all past due amounts plus interest, which the projects expect to collect within the next two years. The SCE agreement to pay these past due amounts is contingent on SCE making certain payments to other creditors. As a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator and Power Exchange, we may be required to pay refunds of between $3 and $4 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. While the process at FERC is ongoing, FERC has indicated that we will have the ability to reduce the potential refund amount in order to recover outstanding receivables we are owed. FERC also has indicated that it will consider adjustments to the refund amount to the extent we can demonstrate that its refund methodology resulted in an overall revenue shortfall for our transactions in these markets during the refund period. Note 12. Risk Management Activities and Fair Value of Financial Instruments - -------------------------------------------------------------------------------- Risk Management Activities - -------------------------- In 2001, we entered into forward starting interest rate swap contracts to manage a portion of our interest rate exposure for anticipated long-term borrowings to refinance our outstanding commercial paper obligations and maturing long-term debt. The swaps have notional or contract amounts that total $800 million with an average rate of 4.9% and expire in the first quarter of 2002. The notional amounts of the contracts do not represent amounts that are exchanged by the parties and are not a measure of our exposure to market or credit risks. The notional amounts are used in the determination of the cash settlements under the contracts. At December 31, 2001, the fair value of these swaps was an unrealized pre-tax gain of $36.3 million. At December 31, 2001, these swaps were designated as cash-flow hedges under SFAS No. 133. We recorded this unrealized gain in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," net of associated deferred income tax effects, in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. Any gain or loss on the hedges will be reclassified from "Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur. In 2002, we entered into additional forward starting interest rate swaps with notional amounts that total $700 million. These swaps have an average rate of 5.9% and expire in the first quarter of 2002. Our power marketing operation manages the commodity price risk of our electric generation operations as part of its overall portfolio. In order to manage this risk, our merchant energy business may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel as discussed in Note 1 on page 13. At December 31, 2001, our merchant energy business had designated certain fixed-price forward electricity sale contracts as cash-flow hedges of forecasted sales of electricity for the years 2002 through 2010 under SFAS No. 133. At December 31, 2001, our merchant energy business recorded net unrealized pre-tax gains of $76.5 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income". We expect to reclassify $5.7 million of net pre-tax gains on cash flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2001. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2001 due to future changes in market prices. In 2001, there was no hedge ineffectiveness recognized in earnings. At December 31, 2000, our merchant energy business recorded deferred pre-tax hedge losses of $58.3 million in "Other deferred charges" in our Consolidated Balance Sheets for the fixed-price forward electricity sale contracts designated as a hedge of forecasted sales of electricity. We reclassified these deferred hedge losses, net of associated deferred income tax effects, to "Accumulated other comprehensive income" upon the adoption of SFAS No. 133, in the first quarter of 2001. Fair Value of Financial Instruments - ----------------------------------- The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We use the following methods and assumptions for estimating fair value disclosures for financial instruments: o cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: because of their short-term nature, the amounts reported in our Consolidated Balance Sheets approximate fair value, o investments and other assets where it was practicable to estimate fair value: the fair value is based on quoted market prices where available, and o for long-term debt: the fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates. 37 We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately later in this section. At December 31, 2001 2000 - ------------------------- ------------------- ------------------ Carrying Fair Carrying Fair Amount Value Amount Value - ------------------------- --------- --------- -------- --------- (In millions) Investments and other assets for which it is: Practicable to estimate fair value $1,144.9 $1,144.9 $ 349.8 $ 349.8 Not practicable to estimate fair value 25.8 N/A 32.7 N/A Fixed-rate long-term debt 2,945.3 3,069.6 2,734.1 2,819.9 Variable-rate long-term debt 1,179.1 1,179.1 1,331.8 1,331.8 It was not practicable to estimate the fair value of investments held by our nonregulated businesses in several financial partnerships that invest in nonpublic debt and equity securities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets. The investments in financial partnerships totaled $25.8 million at December 31, 2001 and $32.7 million at December 31, 2000, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $5.4 billion at December 31, 2000 (which is the latest information available). Guarantees - ---------- It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries. Constellation Energy guaranteed outstanding debt of $47.9 million at December 31, 2001 and $341.0 million at December 31, 2000. Our merchant energy business guaranteed outstanding debt totaling $414.8 million at December 31, 2001 and $33.6 million at December 31, 2000. Our other nonregulated businesses guaranteed outstanding debt totaling $15.9 million at December 31, 2001 and $16.5 million at December 31, 2000. BGE guaranteed outstanding debt of $263.3 million at December 31, 2001 and 2000. We do not anticipate that we will need to fund these guarantees. 38 Note 13. Stock-Based Compensation - -------------------------------------------------------------------------------- As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under our existing long-term incentive plans, we can issue awards that include stock options and performance-based restricted stock to officers and key employees. Under the plans, we can issue up to a total of 6,000,000 shares for these awards. Stock Options - ------------- In May 2000, our Board of Directors approved the issuance of nonqualified stock options. Options have been granted at prices not less than the market value of the stock at the date of grant, generally become exercisable ratably over a three-year period beginning one-year from the date of grant, and expire ten years from the date of grant. In accordance with APB No. 25, no compensation expense is recognized for the stock option awards. Summarized information for our stock option awards is as follows: 2001 2000 - ------------------ --------------------- -------------------- Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price - ------------------ ---------- ---------- --------- ---------- (In thousands, except per share amounts) Outstanding, beginning of year 2,420 $34.65 -- $ -- Granted 1,015 25.08 2,462 34.64 Exercised (512) (34.25) -- -- Cancelled/ Expired (277) (37.74) (42) (34.25) - ------------------ --------- ----------- --------- ---------- Outstanding, end of year 2,646 $30.73 2,420 $34.65 ================== ========= =========== ========= ========== Exercisable, end of year 235 $34.25 -- -- ================== ========= =========== ========= ========== Weighted-average fair value per share of options granted $9.27 $5.60 ================== ========= =========== ========= ========== The following table summarizes information about stock options outstanding at December 31, 2001 (shares in thousands): Weighted-Average Remaining Exercise Number Contractual Number Plan Year Prices Outstanding Life Exercisable - ---------- ------------ ------------ ---------------- ------------ 2001 $25.08 1,015 9.9 -- 2000 $34.25 1,631 8.4 235 Performance-Based Restricted Stock Awards - ----------------------------------------- In addition, we issue common stock based on meeting certain performance and service goals over a three to five year period. This stock vests to participants at various times ranging from three to five years or less. In accordance with APB No. 25, we recognize compensation expense for our restricted stock awards using the variable accounting method. In 2001, due to non-attainment of performance criteria, we recorded a credit to compensation expense of $10.1 million. We recorded compensation expense of $16.3 million for 2000 and $10.5 million for 1999. Summarized share information for our restricted stock awards is as follows: 2001 2000 1999 - ---------------------------------- ------- -------- --------- (In thousands, except per share amounts) Outstanding, beginning of year 377 323 350 Granted 87 353 358 Released to participants -- (277) (362) Cancelled (29) (22) (23) - ---------------------------------- ------- -------- --------- Available for grant, end of year 435 377 323 ================================== ======= ======== ========= Weighted-average fair value restricted stock granted $35.24 $32.89 $28.61 ================================== ======= ======== ========= Pro-forma Information - --------------------- Disclosure of pro-forma information regarding net income and earnings per share is required under SFAS No. 123, which uses the fair value method. The fair values of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions: 2001 2000 - --------------------------- ---------- ---------- Risk-free interest rate 4.79% 6.37% Expected life (in years) 5.0 10.0 Expected market price volatility factors 41.3% 21.0% Expected dividend yields 1.8% 5.7% Had compensation cost for these plans been recognized under the fair value method, net income and basic and diluted earnings per share amounts would have been as follows: 2001 - --------------------------------- --------- (In millions, except per share amounts) Pro-forma net income $87.2 Pro-forma earnings per share: Basic $ .54 Diluted $ .54 The effect of applying SFAS No. 123 to our stock-based awards results in net income and earnings per share that are not materially different from amounts reported for the year ended December 31, 2000. 39 Note 14. Acquisition of Nine Mile Point - -------------------------------------------------------------------------------- On November 7, 2001, we completed our purchase of Nine Mile Point located in Scriba, New York. Nine Mile Point consists of two boiling-water reactors. Unit 1 is a 609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148-megawatt reactor that began operation in 1988. Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2. Approximately one-half of the purchase price, or $380 million, in addition to settlement costs of $2.7 million, was paid at closing and the remainder is being financed through the sellers in a note to be repaid over five years with an interest rate of 11.0%. This note may be prepaid at any time without penalty. The sellers also transferred to us approximately $442 million in decommissioning funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity. Niagara Mohawk Power Corporation was the sole owner of Nine Mile Point Unit 1. The co-owners of Unit 2 who sold their interests are: Niagara Mohawk (41 percent), New York State Electric and Gas (18 percent), Rochester Gas & Electric Corporation (14 percent) and Central Hudson Gas & Electric Corporation (9 percent). The Long Island Power Authority will continue to own 18 percent of Unit 2. We will sell 90 percent of our share of Nine Mile Point's output back to the sellers at an average price of nearly $35 per megawatt-hour for approximately 10 years under power purchase agreements. The contracts for the output are on a unit contingent basis (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources). Nine Mile Point Net Assets Acquired - ----------------------------------- At November 7, 2001 (In millions) - ------------------------------------ -------------------- Current Assets $ 135.4 Nuclear Decommissioning Trust Fund 441.7 Net Property, Plant and Equipment 292.6 Intangible Assets (details below) 38.7 - ------------------------------------ -------------------- Total Assets Acquired 908.4 Current Liabilities 16.9 Deferred Credits and Other Liabilities 120.7 - ------------------------------------ -------------------- Net Assets Acquired 770.8 Note to Sellers 388.1 - ------------------------------------ -------------------- Total Cash Paid $ 382.7 ==================================== ==================== The intangible assets acquired consist of the following: Weighted-Average Description Amount Useful Life - ------------------------- ------------- ---------------- (In millions) (In years) Operating procedures and manuals $ 23.4 10 Permits and licenses 12.9 27 Software 2.4 5 - ------------------------- ------------- Total intangible assets $ 38.7 ========================= ============= In 2002, Niagara Mohawk, or its successor, will provide funds equal to the net pension obligation of Nine Mile Point employees following a more precise estimate of this obligation. 40 Note 15. Quarterly Financial Data (Unaudited) - -------------------------------------------------------------------------------- Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. 2001 Quarterly Data - ------------------- Earnings Applicable Earnings Income to Per Share from Common Common Revenue Operations Stock Stock - ---------------- -------- ---------- ---------- --------- (In millions, except per share amounts) Quarter Ended March 31 $1,147.1 $235.0 $111.8 $0.74 June 30 843.2 171.0 75.6 0.46 September 30 1,036.1 317.5 163.6 1.00 December 31 901.9 (365.7) (260.1) (1.59) - --------------- ---------- --------- ---------- --------- Year Ended December 31 $3,928.3 $357.8 $ 90.9 $0.57 =============== ========== ========= ========== ========= Our first quarter results include a $8.5 million after-tax gain for the cumulative effect of adopting SFAS No. 133. Our fourth quarter results include workforce reduction costs, contract termination related costs, and impairment losses and other costs totaling $334.8 million after-tax. For details, refer to Note 2 on page 18. 2000 Quarterly Data - ------------------- Earnings Applicable Earnings Income to Per Share from Common Common Revenue Operations Stock Stock - ---------------- -------- ---------- ---------- --------- (In millions, except per share amounts) Quarter Ended March 31 $994.0 $184.6 $ 72.1 $0.48 June 30 866.6 132.1 39.6 0.26 September 30 968.6 313.4 147.5 0.98 December 31 1,023.3 212.5 86.1 0.57 - --------------- ---------- --------- ---------- --------- Year Ended December 31 $3,852.5 $842.6 $345.3 $2.30 =============== ========== ========= ========== ========= Our first quarter results include a $2.5 million after-tax expense for BGE employees that elected to participate in a targeted VSERP (see Note 2). Our second quarter results include: o a $15.0 million after-tax deregulation transition cost to Goldman Sachs incurred by our power marketing operation to provide BGE's standard offer service requirements (see Note 3), and o a $1.7 million after-tax expense for the VSERP (see Note 2). The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 41 -----END PRIVACY-ENHANCED MESSAGE-----