-----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, EHkj8jZNjawC4Pt3AIAzX0Qtp/GnoQ1MYe8fX5sLlgPBBiQFFSHKQjH/NJl+yCJR Ik7X6bF1/i/mA5NJ7vzpBA== 0001004440-02-000117.txt : 20020515 0001004440-02-000117.hdr.sgml : 20020515 20020515121001 ACCESSION NUMBER: 0001004440-02-000117 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020515 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: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 02649599 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: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-25931 FILM NUMBER: 02649600 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 10-Q 1 f10q.txt FORM 10Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended MARCH 31, 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 of Incorporation) 250 W. PRATT STREET, BALTIMORE, MARYLAND 21201 ---------------------------------------------------------------- (Address of principal executive offices) (Zip Code) 410-234-5000 ------------------------------------------------------ (Registrants' telephone number, including area code) NOT APPLICABLE --------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes X No ---------- ------------ Common Stock, without par value 164,031,496 shares outstanding of Constellation Energy Group, Inc. on April 30, 2002. TABLE OF CONTENTS
Page Part I -- Financial Information Item 1 -- Financial Statements Constellation Energy Group, Inc. and Subsidiaries Consolidated Statements of Income...................................................... 3 Consolidated Statements of Comprehensive Income........................................ 3 Consolidated Balance Sheets............................................................ 4 Consolidated Statements of Cash Flows.................................................. 6 Baltimore Gas and Electric Company and Subsidiaries Consolidated Statements of Income...................................................... 7 Consolidated Balance Sheets............................................................ 8 Consolidated Statements of Cash Flows.................................................. 10 Notes to Consolidated Financial Statements............................................. 11 Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction........................................................................... 19 Application of Critical Accounting Policies............................................ 20 Events of 2002......................................................................... 21 Strategy............................................................................... 22 Business Environment................................................................... 23 Results of Operations.................................................................. 26 Financial Condition.................................................................... 38 Capital Resources...................................................................... 39 Other Matters.......................................................................... 41 Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 41 Part II -- Other Information Item 1 -- Legal Proceedings...................................................................... 42 Item 5 -- Other Information...................................................................... 43 Item 6 -- Exhibits and Reports on Form 8-K....................................................... 44 Signature........................................................................................ 45
2 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended March 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions, except per share amounts) Revenues Nonregulated revenues $ 364.8 $ 286.0 Regulated electric revenues 460.3 492.2 Regulated gas revenues 220.8 352.3 - ------------------------------------------------------------------------------------------------------------------------------------ Total revenues 1,045.9 1,130.5 Expenses Operating expenses 669.9 750.1 Workforce reduction costs 25.9 -- Depreciation and amortization 117.1 103.6 Taxes other than income taxes 65.6 58.4 - ------------------------------------------------------------------------------------------------------------------------------------ Total expenses 878.5 912.1 Gains on Sale of Investments 257.1 16.6 - ------------------------------------------------------------------------------------------------------------------------------------ Income from Operations 424.5 235.0 Other Expense 2.2 1.2 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Fixed Charges and Income Taxes 422.3 233.8 Fixed Charges Interest expense (net) 67.1 78.0 Interest capitalized and allowance for borrowed funds used during construction (11.8) (15.3) BGE preference stock dividends 3.3 3.3 - ------------------------------------------------------------------------------------------------------------------------------------ Total fixed charges 58.6 66.0 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Income Taxes 363.7 167.8 Income Taxes Current 161.0 75.9 Deferred (23.9) (9.3) Investment tax credit adjustments (2.0) (2.1) - ------------------------------------------------------------------------------------------------------------------------------------ Total income taxes 135.1 64.5 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Cumulative Effect of Change in Accounting Principle 228.6 103.3 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 -- 8.5 - ------------------------------------------------------------------------------------------------------------------------------------ Net Income $ 228.6 $ 111.8 ==================================================================================================================================== Earnings Applicable to Common Stock $ 228.6 $ 111.8 ==================================================================================================================================== Average Shares of Common Stock Outstanding 163.7 151.8 Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution Before Cumulative Effect of Change in Accounting Principle $1.40 $0.68 Cumulative Effect of Change in Accounting Principle -- 0.06 - ------------------------------------------------------------------------------------------------------------------------------------ Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution $1.40 $0.74 Dividends Declared Per Common Share $0.24 $0.12 Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Net Income $228.6 $111.8 Reclassification adjustment--gains on sale of investments included in net income, net of taxes (154.9) (9.5) Other comprehensive loss, net of taxes (47.7) (4.8) - ------------------------------------------------------------------------------------------------------------------------------------ Comprehensive Income Before Cumulative Effect of Change in Accounting Principle 26.0 97.5 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6 -- (35.5) - ------------------------------------------------------------------------------------------------------------------------------------ Comprehensive Income $ 26.0 $ 62.0 ====================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 3 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2002* 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Assets Current Assets Cash and cash equivalents $ 1,042.1 $ 72.4 Accounts receivable (net of allowance for uncollectibles of $24.6 and $22.8 respectively) 882.1 738.9 Trading securities 168.7 178.2 Mark-to-market energy assets 637.4 398.4 Fuel stocks 81.2 108.0 Materials and supplies 196.7 205.3 Prepaid taxes other than income taxes 46.8 93.4 Other 28.2 65.6 - ------------------------------------------------------------------------------------------------------------------------------------ Total current assets 3,083.2 1,860.2 - ------------------------------------------------------------------------------------------------------------------------------------ Investments and Other Assets Real estate projects and investments 104.0 210.7 Investments in power projects 474.5 499.1 Investment in Orion Power Holdings, Inc. -- 442.5 Financial investments 42.7 60.7 Nuclear decommissioning trust funds 683.5 683.5 Mark-to-market energy assets 853.0 1,819.8 Other 235.8 207.4 - ------------------------------------------------------------------------------------------------------------------------------------ Total investments and other assets 2,393.5 3,923.7 - ------------------------------------------------------------------------------------------------------------------------------------ Property, Plant and Equipment Regulated property, plant and equipment 4,971.0 4,948.7 Nonregulated generation property, plant and equipment 6,662.2 6,551.1 Other nonregulated property, plant and equipment 194.4 192.9 Nuclear fuel (net of amortization) 199.1 169.5 Accumulated depreciation (4,215.3) (4,161.8) - ------------------------------------------------------------------------------------------------------------------------------------ Net property, plant and equipment 7,811.4 7,700.4 - ------------------------------------------------------------------------------------------------------------------------------------ Deferred Charges Regulatory assets (net) 429.8 463.8 Other 135.4 129.5 - ------------------------------------------------------------------------------------------------------------------------------------ Total deferred charges 565.2 593.3 - ------------------------------------------------------------------------------------------------------------------------------------ Total Assets $13,853.3 $14,077.6 ====================================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 4 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2002* 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 199.2 $ 975.0 Current portions of long-term debt 706.6 1,406.7 Accounts payable 747.9 523.3 Mark-to-market energy liabilities 575.6 323.3 Accrued taxes 159.3 9.1 Dividends declared 42.6 23.0 Other 269.7 299.1 - ------------------------------------------------------------------------------------------------------------------------------------ Total current liabilities 2,700.9 3,559.5 - ------------------------------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Deferred income taxes 1,279.2 1,431.0 Mark-to-market energy liabilities 549.7 1,476.5 Net pension liability 170.8 173.3 Postretirement and postemployment benefits 345.8 330.9 Deferred investment tax credits 91.5 93.4 Other 295.9 266.9 - ------------------------------------------------------------------------------------------------------------------------------------ Total deferred credits and other liabilities 2,732.9 3,772.0 - ------------------------------------------------------------------------------------------------------------------------------------ Long-term Debt Long-term debt of Constellation Energy 2,100.0 935.0 Long-term debt of nonregulated businesses 795.6 769.1 First refunding mortgage bonds of BGE 1,040.7 1,040.7 Other long-term debt of BGE 929.6 1,129.6 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0 Unamortized discount and premium (11.5) (5.2) Current portions of long-term debt (706.6) (1,406.7) - ------------------------------------------------------------------------------------------------------------------------------------ Total long-term debt 4,397.8 2,712.5 - ------------------------------------------------------------------------------------------------------------------------------------ BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholders' Equity Common stock 2,043.7 2,042.2 Retained earnings 1,800.7 1,611.5 Accumulated other comprehensive (loss) income (12.7) 189.9 - ------------------------------------------------------------------------------------------------------------------------------------ Total common shareholders' equity 3,831.7 3,843.6 - ------------------------------------------------------------------------------------------------------------------------------------ Total capitalization 8,419.5 6,746.1 - ------------------------------------------------------------------------------------------------------------------------------------ Total Liabilities and Capitalization $13,853.3 $14,077.6 ====================================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 5 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Cash Flows From Operating Activities Net income $ 228.6 $111.8 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle -- (8.5) Depreciation and amortization 124.5 115.8 Deferred income taxes (23.9) (9.3) Investment tax credit adjustments (2.0) (2.1) Deferred fuel costs 25.5 13.2 Accrued pension and postemployment benefits 16.9 11.7 Gains on sale of investments (257.1) (16.6) Gain on sale of plant assets -- (9.5) Workforce reduction costs 25.9 -- Equity in earnings of affiliates and joint ventures (net) 26.4 (10.6) Changes in mark-to-market energy assets and liabilities 53.3 (46.1) Changes in other current assets (59.7) 176.9 Changes in other current liabilities 361.5 (167.9) Other (85.0) 35.9 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 434.9 194.7 - ------------------------------------------------------------------------------------------------------------------------------------ Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (226.5) (353.9) Contributions to nuclear decommissioning trust funds (0.2) (8.8) Purchases of marketable equity securities (0.2) (15.1) Sales of marketable equity securities 29.9 44.3 Sales of investments 555.4 -- Sale of property, plant and equipment -- 49.5 Other investments 7.7 5.1 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by (used in) investing activities 366.1 (278.9) - ------------------------------------------------------------------------------------------------------------------------------------ Cash Flows From Financing Activities Net maturity of short-term borrowings (775.8) (153.5) Proceeds from issuance of Long-term debt 1,821.0 401.0 Common stock -- 504.4 Repayment of long-term debt (848.5) (284.3) Common stock dividends paid (19.7) (63.2) Other (8.3) 15.7 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by financing activities 168.7 420.1 - ------------------------------------------------------------------------------------------------------------------------------------ Net Increase in Cash and Cash Equivalents 969.7 335.9 Cash and Cash Equivalents at Beginning of Period 72.4 182.7 - ------------------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Period $1,042.1 $518.6 ==================================================================================================================================== Other Cash Flow Information Cash paid (received) during the period for: Interest (net of amounts capitalized) $ 47.0 $55.4 Income taxes $(14.0) $18.7
See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 6 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended March 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Revenues Electric revenues $460.4 $492.3 Gas revenues 223.3 357.6 - ------------------------------------------------------------------------------------------------------------------------------------ Total revenues 683.7 849.9 Expenses Operating expenses: Electric fuel and purchased energy 240.5 265.8 Gas purchased for resale 124.3 252.9 Operations and maintenance 84.5 86.4 Workforce reduction costs 20.9 -- Depreciation and amortization 56.5 57.7 Taxes other than income taxes 44.0 46.0 - ------------------------------------------------------------------------------------------------------------------------------------ Total expenses 570.7 708.8 - ------------------------------------------------------------------------------------------------------------------------------------ Income from Operations 113.0 141.1 Other Expense 0.7 2.2 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Fixed Charges and Income Taxes 112.3 138.9 Fixed Charges Interest expense (net) 34.5 42.3 Allowance for borrowed funds used during construction (0.4) (0.3) - ------------------------------------------------------------------------------------------------------------------------------------ Total fixed charges 34.1 42.0 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Income Taxes 78.2 96.9 Income Taxes Current 46.9 40.8 Deferred (15.4) (1.7) Investment tax credit adjustments (0.5) (0.6) - ------------------------------------------------------------------------------------------------------------------------------------ Total income taxes 31.0 38.5 - ------------------------------------------------------------------------------------------------------------------------------------ Net Income 47.2 58.4 Preference Stock Dividends 3.3 3.3 - ------------------------------------------------------------------------------------------------------------------------------------ Earnings Applicable to Common Stock $ 43.9 $ 55.1 ====================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 7 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2002* 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Assets Current Assets Cash and cash equivalents $ 24.1 $ 37.4 Accounts receivable (net of allowance for uncollectibles of $14.0 and $13.4 respectively) 334.1 295.2 Accounts receivable, affiliated companies 558.7 572.5 Fuel stocks 9.5 52.3 Materials and supplies 37.6 33.1 Prepaid taxes other than income taxes 23.0 72.5 Other 7.2 7.6 - ------------------------------------------------------------------------------------------------------------------------------------ Total current assets 994.2 1,070.6 - ------------------------------------------------------------------------------------------------------------------------------------ Other Assets Receivable, affiliated company 64.8 113.3 Other 78.0 74.5 - ------------------------------------------------------------------------------------------------------------------------------------ Other assets 142.8 187.8 - ------------------------------------------------------------------------------------------------------------------------------------ Utility Plant Plant in service Electric 3,365.7 3,349.9 Gas 1,019.5 1,014.4 Common 494.7 498.1 - ------------------------------------------------------------------------------------------------------------------------------------ Total plant in service 4,879.9 4,862.4 Accumulated depreciation (1,781.5) (1,751.4) - ------------------------------------------------------------------------------------------------------------------------------------ Net plant in service 3,098.4 3,111.0 Construction work in progress 86.6 81.8 Plant held for future use 4.5 4.5 - ------------------------------------------------------------------------------------------------------------------------------------ Net utility plant 3,189.5 3,197.3 - ------------------------------------------------------------------------------------------------------------------------------------ Deferred Charges Regulatory assets (net) 429.8 463.8 Other 32.7 35.0 - ------------------------------------------------------------------------------------------------------------------------------------ Total deferred charges 462.5 498.8 - ------------------------------------------------------------------------------------------------------------------------------------ Total Assets $4,789.0 $4,954.5 ====================================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. 8 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2002* 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Liabilities and Capitalization Current Liabilities Current portions of long-term debt $ 601.1 $ 666.3 Accounts payable 57.6 63.6 Accounts payable, affiliated companies 73.6 92.6 Customer deposits 51.1 50.0 Accrued taxes 53.8 7.6 Accrued interest 47.0 37.0 Accrued vacation costs 21.7 21.7 Other 18.9 39.2 - ------------------------------------------------------------------------------------------------------------------------------------ Total current liabilities 924.8 978.0 - ------------------------------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Deferred income taxes 486.9 503.1 Postretirement and postemployment benefits 276.7 266.1 Deferred investment tax credits 22.1 22.7 Decommissioning of federal uranium enrichment facilities 19.3 19.3 Other 21.9 22.2 - ------------------------------------------------------------------------------------------------------------------------------------ Total deferred credits and other liabilities 826.9 833.4 - ------------------------------------------------------------------------------------------------------------------------------------ Long-term Debt First refunding mortgage bonds of BGE 1,040.7 1,040.7 Other long-term debt of BGE 929.6 1,129.6 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0 Long-term debt of nonregulated businesses 58.0 71.0 Unamortized discount and premium (5.1) (3.3) Current portions of long-term debt (601.1) (666.3) - ------------------------------------------------------------------------------------------------------------------------------------ Total long-term debt 1,672.1 1,821.7 - ------------------------------------------------------------------------------------------------------------------------------------ Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 711.9 711.9 Retained earnings 463.3 419.5 - ------------------------------------------------------------------------------------------------------------------------------------ Total common shareholder's equity 1,175.2 1,131.4 - ------------------------------------------------------------------------------------------------------------------------------------ Total capitalization 3,037.3 3,143.1 - ------------------------------------------------------------------------------------------------------------------------------------ Total Liabilities and Capitalization $4,789.0 $4,954.5 ====================================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. 9 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Cash Flows From Operating Activities Net income $ 47.2 $ 58.4 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 57.2 58.3 Deferred income taxes (15.4) (1.7) Investment tax credit adjustments (0.5) (0.6) Deferred fuel costs 25.5 13.2 Accrued pension and postemployment benefits 6.8 7.5 Workforce reduction costs 20.9 -- Allowance for equity funds used during construction (0.7) (0.7) Changes in other current assets 78.1 71.2 Changes in other current liabilities 20.3 (13.3) Other 7.5 12.9 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 246.9 205.2 - ------------------------------------------------------------------------------------------------------------------------------------ Cash Flows From Investing Activities Utility construction expenditures (excluding AFC) (40.1) (58.9) Other (3.8) (4.2) - ------------------------------------------------------------------------------------------------------------------------------------ Net cash used in investing activities (43.9) (63.1) - ------------------------------------------------------------------------------------------------------------------------------------ Cash Flows From Financing Activities Net maturity of short-term borrowings -- (32.1) Proceeds from issuance of long-term debt -- 3.0 Repayment of long-term debt (213.0) -- Preference stock dividends paid (3.3) (3.3) - ------------------------------------------------------------------------------------------------------------------------------------ Net cash used in financing activities (216.3) (32.4) - ------------------------------------------------------------------------------------------------------------------------------------ Net (Decrease) Increase in Cash and Cash Equivalents (13.3) 109.7 Cash and Cash Equivalents at Beginning of Period 37.4 21.3 - ------------------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Period $ 24.1 $131.0 ==================================================================================================================================== Other Cash Flow Information Cash paid (received) during the period for: Interest (net of amounts capitalized) $ 26.4 $42.1 Income taxes $(20.5) $13.3
See Notes to Consolidated Financial Statements. Certain prior-period amounts have been reclassified to conform with the current period's presentation. 10 Notes to Consolidated Financial Statements - ------------------------------------------ Weather conditions can have a great impact on our results for interim periods. This means that the results for this quarter are not necessarily indicative of future quarters or full year results given the seasonality of our business. Our interim financial statements on the previous pages reflect all adjustments that management believes are necessary for the fair presentation of the financial position and results of operations for the interim periods presented. These adjustments are of a normal recurring nature. Basis of Presentation - --------------------- This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "utility business" are to BGE. Workforce Reduction Costs - ------------------------- 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. 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. We discuss our workforce reduction programs in more detail in Note 2 of our 2001 Annual Report on Form 10-K. The voluntary programs were designed, offered, and timed to minimize the number of employees who would be involuntarily severed under our overall workforce reduction plan. In 2001, 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 elected to voluntarily retire under the age 50 to 54 VSERP and how many would thereafter be involuntarily severed was unknown until after the election period of the age 50 to 54 VSERP ended 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), we recognized a liability of $25.1 million at December 31, 2001 for the targeted number of involuntary terminations that would have resulted if no employees elected the age 50 to 54 VSERP. In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP, and we involuntary severed 129 employees. The total costs of the involuntary severance program were $7.3 million. As a result, we recorded $25.9 million pre-tax, or $15.6 million after-tax, of additional expense in the first quarter of 2002 for the employees that elected the age 50 to 54 VSERP. BGE recorded $20.9 million pre-tax, or $12.6 million after-tax, of this amount. BGE also recorded $9.2 million on its balance sheet as a regulatory asset related to its gas business. The following table summarizes the status of the involuntary severance liability recorded under EITF 94-3 and the associated gas regulatory asset. Changes in involuntary severance liability and gas regulatory asset - ------------------------------------------------------------------- Amount Amount recorded charged as Involuntary to regulatory severance expense asset liability - ------------------------------------------------------------------- (In millions) Amounts recorded in 2001 $19.3 $ 5.8 $25.1 ========------------------------------- VSERP elections in 2002 $39.5 13.4 52.9 Reduction of involuntary severance accrual for age 50 to 54 VSERP elections (13.6) (4.2) (17.8) - ------------------------------------------------------------------- Amounts recorded in 2002 $25.9 9.2 35.1 ======== Cash payments made in 2002 (3.3) Amount transferred to long-term pension and postretirement obligations (52.9) Amortization of regulatory asset (0.3) - ---------------------------- ----------------------------- Balance at March 31, 2002 $14.7 $ 4.0 - ---------------------------- ============================= The amount transferred to the long-term pension and postretirement obligations are recorded as liabilities in "Net pension liability" and "Postretirement and postemployment benefits" in our Consolidated Balance Sheets. Investment in Orion - ------------------- In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares of Orion Power Holdings, Inc. (Orion) for $26.80 per share, including the shares we owned of Orion. We received cash proceeds of $454.1 million and recognized a gain of $255.5 million pre-tax, or $163.3 million after-tax, on the sale of our investment. 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 approximated the book value of our investment. 11 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, and o Our regulated gas business purchases, transports, and sells natural gas in Maryland. 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. As previously discussed in our 2001 Annual Report on Form 10-K, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. These assets include certain real estate, senior-living facilities, and international power projects. In addition, we initiated a liquidation program for our financial investments operation and expect to sell substantially all of our investments in this operation by the end of 2003. 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 in the table below. We have restated certain prior-period information for comparative purposes based on our reportable operating segments.
Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated - --------------------------- -------------- -------------- ------------- -------------- --------------- ------------- For the three months ended March 31, (In millions) 2002 - ---- Unaffiliated revenues $243.1 $460.3 $220.8 $121.7 $ -- $1,045.9 Intersegment revenues 229.2 0.1 2.5 (1.3) (230.5) -- - ---------------------------- -------------- -------------- ------------- -------------- --------------- ------------ Total revenues 472.3 460.4 223.3 120.4 (230.5) 1,045.9 Net income 27.0 16.4 27.8 157.4 -- 228.6 2001 - ---- Unaffiliated revenues $ 95.0 $492.2 $352.3 $191.0 $ -- $1,130.5 Intersegment revenues 250.8 0.1 5.3 22.7 (278.9) -- - ---------------------------- -------------- -------------- ------------- -------------- --------------- ------------ Total revenues 345.8 492.3 357.6 213.7 (278.9) 1,130.5 Cumulative effect of change in accounting principle -- -- -- 8.5 -- 8.5 Net income 42.4 27.7 28.7 13.0 -- 111.8
12 Financing Activity - ------------------ Constellation Energy - -------------------- Constellation Energy issued the following notes during the period from January 1, 2002 through the date of this report: Date Net Principal Issued Proceeds - ------------------------------ -------- --------- --------- (In millions) 6.35% Fixed Rate Notes $600.0 3/02 $595.4 7.00% Fixed Rate Notes 600.0 3/02 592.9 7.60% Fixed Rate Notes 600.0 3/02 592.8 We used a portion of the net proceeds from the sale of these notes to repay short-term borrowings and, in April 2002, we used a portion to prepay the sellers' note of $388.1 million originally issued for the acquisition of Nine Mile Point Nuclear Station (Nine Mile Point). In June 2001, Constellation Energy arranged a $2.5 billion, 364-day revolving credit facility. In March 2002, this facility was reduced from $2.5 billion to $700.0 million. We use 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. Constellation Energy also has an existing $188.5 million, multi-year revolving credit facility available for short-term and long-term needs, including letters of credit. At March 31, 2002, letters of credit that totaled $335.4 million were issued under all of our facilities. BGE and Nonregulated Businesses - ------------------------------- In conjunction with the July 1, 2000 transfer of generation assets, BGE currently is contingently liable for $276 million of the tax exempt debt that was assigned to nonregulated affiliates of Constellation Energy. In the future, BGE may purchase some of its long-term debt or preference stock in the market depending on market conditions and BGE's capital structure. Please refer to the Funding for Capital Requirements section of Management's Discussion and Analysis on page 40 for additional information about the debt of BGE and our nonregulated businesses. Commitments - ----------- Our merchant energy business enters into long-term contracts for: o the purchase of electric generating capacity and energy, o the procurement and delivery of fuels to supply our generating plant requirements, and o the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. 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 it has an interest. Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. BGE Home Products & Services also has gas purchase commitments related to its gas sales program which expire in 2003. At March 31, 2002, the total amount of investment requirements committed was $895.9 million. 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 - --------- 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. 13 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 SO2 allowance banks. Our projects comply with the SO2 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 31, 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 and Wagner facilities, we installed emission reduction equipment 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 our costs for the equipment needed at the Keystone plant will be approximately $35 million. Through March 31, 2002, we have spent approximately $6 million. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. In 1999, these new standards were successfully challenged in court. The EPA appealed the 1999 court rulings to the Supreme Court. In February 2001, the Supreme Court upheld EPA's authority to issue the standards. However, the Supreme Court sent the case back to the lower court and EPA for further proceedings on implementation issues related to the revised ozone standard. On March 26, 2002, the lower court upheld EPA's promulgation of both the revised ozone and very fine particulate standards. While these standards may require increased controls at our fossil generating plants in the future, implementation could be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, Pennsylvania, and California, still need to determine what reductions in pollutants will be necessary to meet the EPA standards. 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 14 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 material. 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, BGE signed a consent order with the Maryland Department of the Environment (MDE) that required it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. BGE submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs BGE considers to be probable to remedy the contamination are estimated to total $47 million. BGE has recorded these costs as a liability on its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. We discuss this further in Note 6 of our 2001 Annual Report on Form 10-K. Because of the results of studies at this site, it is reasonably possible that these additional costs could exceed the amount BGE recognized by approximately $14 million. Through March 31, 2002, BGE has spent approximately $38 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. Other potential environmental liabilities and pending environmental actions are described further in our 2001 Annual Report on Form 10-K in Item 1. Business - Environmental Matters. 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 discussion on the next page for an 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. 15 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 at any commercial reactor in the country, 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 policies 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 $277.9 million invested in operating power projects of which our ownership percentage represents 137 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 March 31, 2002, we received $28 million of the $45 million for unpaid power sales plus interest, which included payment of 100% of the SCE outstanding balance. We expect to collect the remaining outstanding balance plus interest from PGE within the next year. Accordingly, we reversed all of our $9.1 million credit reserves in the first quarter of 2002 associated with these power sales. These projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. 16 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. As part of the settlement agreement we signed with various California entities in regard to our High Desert Power Project discussed in the Events of 2002 section on page 21, the California entities have made a filing with the FERC disclaiming any right they may have to a refund. Related Party Transactions - BGE - -------------------------------- Income Statement - ---------------- Under the Restructuring Order, BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period from July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier. Constellation Power Source is under contract to provide BGE with 100% of the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period, and 90% of the energy and capacity for the final three years (July 1, 2003 through June 30, 2006) of the transition period. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $241.0 million for the quarter ended March 31, 2002 compared to $251.3 million for the quarter ended March 31, 2001. In addition, BGE is charged by Constellation Energy for certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were approximately $3.7 million for the quarters ended March 31, 2002 and 2001. Balance Sheet - ------------- BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments. BGE had invested $463.7 million at March 31, 2002 and $439.1 million at December 31, 2001 under this arrangement. Amounts related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, and BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them result in intercompany balances on BGE's Consolidated Balance Sheets. Risk Management and Hedging Activities - -------------------------------------- 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. Interest Rate Risk - ------------------ 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 Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities with gains, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income," in our Consolidated Balance Sheets, in anticipation of planned financing transactions. Any gain or loss on the hedges is reclassified from "Accumulated other comprehensive income" into "Interest expense" and included in earnings during the periods in which the interest payments being hedged occur. Prior to the March 2002 issuance of $1.8 billion of debt as discussed in the Financing Activity section on page 13, we entered into various forward starting interest rate swap contracts to manage our interest rate exposure related to this debt issuance. In 2001, we entered into swaps that had notional or contract amounts that totaled $800 million with an average rate of 4.9%. In 2002, we entered into additional forward starting interest rate swaps with notional amounts that totaled $700 million with an average rate of 5.9%. All of these swap contracts expired at the end of March 2002 for a gain of $53.7 million. We will reclassify this gain from "Accumulated other comprehensive income" into "Interest expense" and include it in earnings during the periods in which the hedged interest payments occur. Commodity Price Risk - -------------------- The origination and risk management operation manages market risk on a portfolio basis, subject to established risk management policies. The origination and risk management 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. 17 As part of its overall portfolio, the origination and risk management 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. At March 31, 2002, 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. Under the provisions of SFAS No. 133, we record gains and losses on derivative contracts designated as cash-flow hedges of forecasted transactions in "Accumulated other comprehensive income" in our Consolidated Balance Sheets 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," in our Consolidated Balance Sheets. At March 31, 2002, our merchant energy business recorded net unrealized pre-tax losses of $16.3 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income." We expect to reclassify $0.4 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at March 31, 2002. However, the actual amount reclassified into earnings could vary from the amounts recorded at March 31, 2002 due to future changes in market prices. During the quarter ended March 31, 2002, we recognized into earnings a pre-tax loss of $2.1 million for the ineffectiveness portion related to our hedges. Re-designation of Texas Business - -------------------------------- During February 2002, we re-designated our Texas load-serving business from trading to non-trading (accrual accounting) under Emerging Issues Task Force Issue (EITF) 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As a result of the changes in our organization and senior management in late 2001, including the cancellation of business separation and termination of the power business services agreement with Goldman Sachs, we re-evaluated our load-serving activities. We manage these activities as a physical delivery business rather than a trading business. In Texas, we serve our customers' energy requirements using physically delivering power purchase agreements and our Rio Nogales plant, which is currently undergoing start-up activities and is scheduled to be placed in service in the summer of 2002. Further, changes in the Texas market in mid-February 2002 significantly reduced trading activity and the ability to manage load-serving transactions through trading activities. Based upon these factors, we began to manage our Texas load-serving activities as a physical delivery business separate from our trading activities and re-designated these activities as non-trading effective February 15, 2002. We believe that this designation more accurately reflects the substance of our Texas load-serving physical delivery business. At the time of this change in designation, we reclassified the fair value of load-serving contracts and physically delivering power purchase agreements in Texas from "Mark-to-market energy assets and liabilities" to "Other assets" and "Other deferred credits and other liabilities." The contracts reclassified consisted of gross assets of $78 million and gross liabilities of $15 million, or a net asset of $63 million. Beginning February 15, 2002, the results of our Texas load-serving business are included in "Nonregulated revenues" on a gross basis as power is delivered to our customers. In addition, the costs associated with our Texas load-serving business are included in "Operating expenses" when incurred. Prior to that date, the results of these activities were reported on a net basis as part of mark-to-market energy revenues included in "Nonregulated revenues." Accounting Standards Issued - --------------------------- In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets. 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 the impact on our financial results. In 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. The Statement updates, clarifies, and simplifies existing accounting pronouncements. We do not expect the adoption of this statement to have a material impact on our financial results. 18 Item 2. Management's Discussion - ------------------------------- Management's Discussion and Analysis of Financial Condition and Results of - -------------------------------------------------------------------------- Operations - ---------- Introduction - ------------ 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 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 the Notes to Consolidated Financial Statements on page 12. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "utility business" are to BGE. This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. Effective July 1, 2000, electric generation was deregulated in Maryland. Also, on July 1, 2000, BGE transferred all of its generation assets and related liabilities at book value to our merchant energy business. We discuss the deregulation of electric generation in the Business Environment section on page 23. Our merchant energy business includes: o fossil, nuclear, and hydroelectric generating facilities, interests in power projects in North America, and nuclear consulting services, and o power marketing, origination transactions, and risk management services. BGE is a regulated electric and gas public transmission and distribution utility company. Our other nonregulated businesses include: o energy products and services, o home products, commercial building systems, and residential and commercial electric and gas retail marketing, o a general partnership, in which BGE is a partner, that provides cooling services for commercial customers in Baltimore, o financial investments, o real estate and senior-living facilities, and o interests in Latin American power generation and distribution projects and investments. As previously discussed in our 2001 Annual Report on Form 10-K and in our Other Nonregulated Businesses section on page 37, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. These assets include certain real estate, senior-living facilities, and international power projects. In addition, we initiated a liquidation program for our financial investments operation and expect to sell substantially all of our investments in this operation by the end of 2003. In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including: o what factors affect our businesses, o what our earnings and costs were in the periods presented, o why earnings and costs changed between periods, o where our earnings came from, o how all of this affects our overall financial condition, o what we expect our expenditures for capital projects to be in the future, and o where we expect to get cash for future capital expenditures. As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters ended March 31, 2002 and 2001. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income. 19 Application of Critical Accounting Policies - ------------------------------------------- Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements that were prepared in accordance with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions when preparing financial statements. 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. The Securities and Exchange Commission (SEC) issued disclosure guidance for accounting policies that management believes are most "critical." The SEC defines these critical accounting policies as those that are both most important to the portrayal of a company's financial condition and results and require management's most difficult, subjective, or complex judgment, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods. Management believes the following accounting policies require us to use more significant judgments and estimates in preparing our financial statements and could represent critical accounting policies as defined by the SEC. We discuss our significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1 of our 2001 Annual Report on Form 10-K. Revenue Recognition / Mark-to-Market Method of Accounting - --------------------------------------------------------- Our subsidiary, Constellation Power Source, uses the mark-to-market method of accounting to account for a portion of its power marketing activities. We record all other revenues in the period earned for services rendered, commodities or products delivered, or contracts settled. Power marketing activities include new origination transactions and risk management activities using contracts for energy, other energy-related commodities, and related derivative contracts. We use the mark-to-market method of accounting for portions of Constellation Power Source's activities 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. We discuss the impact of mark-to-market accounting on our financial results in the Results of Operations -- Merchant Energy Business section on page 27. Evaluation of Assets for Impairment and Other Than Temporary Decline in Value - ----------------------------------------------------------------------------- We are required 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. 20 Events of 2002 - -------------- Dividend Increase - ----------------- On January 30, 2002, we announced an increase in our quarterly dividend to 24 cents per share on our common stock payable April 1, 2002 to holders of record on March 11, 2002. This is equivalent to an annual rate of 96 cents per share. Previously, our quarterly dividend on our common stock was 12 cents per share, equivalent to an annual rate of 48 cents per share. Investment in Orion - ------------------- In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares of Orion Power Holdings, Inc. (Orion) for $26.80 per share, including the shares we owned of Orion. We received cash proceeds of $454.1 million and recognized a gain of $255.5 million pre-tax, or $163.3 million after-tax, on the sale of our investment. 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 approximated the book value of our investment. Workforce Reduction Costs - ------------------------- As discussed in Notes to Consolidated Financial Statements on page 11, 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. 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. The voluntary programs were designed, offered, and timed to minimize the number of employees who would be involuntarily severed under our overall workforce reduction plan. In 2001, 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 elected to voluntarily retire under the age 50 to 54 VSERP and how many would thereafter be involuntarily severed was unknown until after the election period of the age 50 to 54 VSERP ended in February 2002. In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP, and we involuntary severed 129 employees. The total costs of the involuntary severance were $7.3 million. As a result, we recorded $25.9 million pre-tax, or $15.6 million after-tax, of additional expense in the first quarter of 2002 for the employees that elected the age 50 to 54 VSERP. BGE recorded $20.9 million pre-tax, or $12.6 million after-tax, of this amount. BGE also recorded $9.2 million on its balance sheet as a regulatory asset related to its gas business. As a result of our workforce reduction efforts to date, we expect annual cost savings of approximately $72 million. However, we will continue to examine other cost-cutting measures to remain competitive in our business environment. We also expect that a significant number of retiring employees covered by our qualified, basic pension plan will elect to receive their pension benefit in the form of a lump-sum payment in 2002. These lump-sum payments may exceed annual plan service cost and interest expense that could trigger a settlement loss in 2002 estimated to be approximately $20 million. Debt Issuance - ------------- In March 2002, we issued $1.8 billion of debt as discussed in the Notes to Consolidated Financial Statements - Financing Activity section on page 13. In April 2002, we used a portion of these proceeds to prepay the sellers' financed note of $388.1 million related to our purchase of Nine Mile Point Nuclear Station (Nine Mile Point). Renegotiations of our High Desert Power Contracts - ------------------------------------------------- In April 2002, we amended our High Desert Power Project long-term power sales agreement with the State of California to provide revised pricing and more flexibility in the amount of electricity purchased from the plant by the California Department of Water Resources (CDWR) and the timing of such purchases. This amended agreement provides California with the flexibility they desired, while preserving our overall economics and reducing our regulatory, fuel, and legal risks. We also signed a comprehensive settlement agreement with the CDWR, the California Energy Oversight Board (EOB), the California Public Utilities Commission (CPUC), the California Attorney General, and the Governor of California by which each of these parties agreed to release claims against us arising out of the original and renegotiated contracts. Under the settlement agreement, the California parties filed with the Federal Energy Regulatory Commission (FERC) to withdraw us from the regulatory complaint filed at the FERC by the CPUC and EOB against all holders of long-term power contracts alleging that the rates charged under the original contracts were not just and reasonable. In addition, the California parties who filed a complaint at FERC alleging that the participants (including Constellation Power Source) who participated in the California Independent System Operator and 21 California Power Exchange were in violation of their market-based rates authority have filed to withdraw us from that regulatory complaint. We agreed to pay $1.25 million into a school and public buildings energy retrofit fund and another $1.25 million to the Attorney General's office in order to conclude this overall comprehensive settlement package. The new contract is based on a "tolling" structure under which the CDWR will pay a fixed amount per month and pay for fuel and other variable costs. During the term of the contract, which runs from the commercial operation date of the plant until March 31, 2011, the High Desert Power Project will provide energy exclusively to the CDWR. Certain Relationships - --------------------- Michael J. Wallace, prior to becoming President of Constellation Generation Group on January 1, 2002, was a Managing Member and Managing Director and greater than 10% owner of Barrington Energy Partners, LLC. Upon becoming President of Constellation Generation Group, Mr. Wallace terminated his affiliation with Barrington, and no longer holds any ownership interest in it. We paid Barrington Energy Partners approximately $0.7 million for consulting services provided to Constellation Energy and its subsidiary, Constellation Nuclear during the quarter ended March 31, 2002. - -------------------------------------------------------------------------------- Strategy - -------- 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 other businesses and terminated our power business services agreement with Goldman Sachs. Our primary growth strategy centers on our merchant energy business. The strategy for our merchant energy business is to be a leading competitive provider of energy solutions for wholesale customers in North America. Our merchant energy business has electric generation assets located in various regions of the United States and engages in power marketing and risk management activities and provides energy solutions to meet wholesale customers' needs throughout North America. Our merchant energy business integrates electric generation assets with power marketing and risk management of energy and energy-related commodities. This integration allows our merchant energy business to maximize value across energy products, over geographic regions, and over time. Our origination and risk management operation adds value to our generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our origination and risk management operation by providing a source of reliable power supply, enhancing our ability to structure sophisticated products and services for customers, building customer credibility, and providing a physical hedge. Currently, our merchant energy business controls over 11,500 megawatts of generation. We also have approximately 2,900 megawatts of natural gas-fired peaking and combined cycle production facilities under construction in Texas, California, Florida, and Illinois. To achieve our strategic objectives, we expect to continue to support our origination and risk management operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to use a disciplined growth strategy through originating transactions with wholesale customers and by acquiring and developing additional generating facilities when necessary to support our origination and risk management operation. Our merchant energy business will focus on long term, high-value sales of energy, capacity, and related products to distribution companies and other wholesale purchasers, primarily in the regional markets in which end-user electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include the Northeast region, the Mid-Atlantic region, and Texas. The growth of BGE and our retail energy services businesses is expected through focused and disciplined expansion. Customer choice, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve our competitive position, to anticipate and adapt to business environment and regulatory changes, and to maintain a strong balance sheet and an investment-grade credit quality. In the fourth quarter of 2001, we undertook a number of initiatives to reduce our costs towards competitive levels and to ensure that our management and capital resources are focused on our core energy businesses. This included the implementation of workforce reduction programs, termination of all planned development projects not currently under construction, and the acceleration of our exit strategy for certain non-core assets. We also might consider one or more of the following strategies: o the complete or partial separation of BGE's transmission function from its distribution function, o mergers or acquisitions of utility or non-utility businesses or assets, and o sale of assets or one or more businesses. 22 Business Environment - -------------------- With the shift toward customer choice, competition, and the growth of our merchant energy business, various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 43. In this section, we discuss in more detail several issues that affect our businesses. Electric Competition - -------------------- We are facing competition in the sale of electricity in wholesale power markets and to retail customers. Maryland - -------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that has significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland Public Service Commission (Maryland PSC) addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 5 of our 2001 Annual Report on Form 10-K. 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 major provisions of the Restructuring Order are discussed in Note 5 of our 2001 Annual Report on Form 10-K. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000: o All customers can choose their electric energy supplier. 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. These rates will not change before July 2006. o BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related assets and liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related assets and liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period for those customers that do not choose an alternate supplier. Constellation Power Source provides BGE with 100% of the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. In August 2001, BGE entered into contracts with Constellation Power Source to supply 90% and Allegheny Energy Supply Company, LLC to supply the remaining 10% of BGE's standard offer service for the final three years (July 1, 2003 to June 30, 2006) of the transition period. Over the transition period, the standard offer service rate that BGE receives from its customers increases. This is offset by a corresponding decrease in the competitive transition charge BGE receives. Constellation Power Source obtains the energy and capacity to supply BGE's standard offer service obligations from affiliates that own Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy and capacity purchased from the wholesale market, as necessary. Other States - ------------ Several states, other than Maryland, have supported complete deregulation of the electric industry. Other states that were considering deregulation have slowed their plans or postponed consideration. While our merchant energy business may be affected by the slow down in deregulation, the FERC initiatives regarding the formation of larger Regional Transmission Organizations could provide our merchant energy business other opportunities as discussed in the FERC Regulation--Regional Transmission Organizations section on page 25. Our merchant energy business has $277.9 million invested in California operating power projects of which our ownership percentage represents 137 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) 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 March 31, 2002, we received $28 million of the $45 million for unpaid power sales plus interest, which included payment of 100% of the SCE outstanding balance. We expect to collect the remaining outstanding balance plus interest from PGE within the next year. Accordingly, we reversed all of our credit reserves that totaled $9.1 million in the first quarter 2002 associated with these unpaid power sales. These projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. However, as a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator (ISO) 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 23 June 2001. As part of the settlement agreement we signed with various California entities in regard to our High Desert Power Project discussed in the Events of 2002 section on page 21, the California entities have made a filing with the FERC disclaiming any right they may have to a refund. The situation with PGE and SCE has not had a material impact on our financial results. However, we cannot provide any assurance that the events in California will not have a material, adverse impact on our financial results, or that any legislative, regulatory, or other solution enacted in California will not have a negative effect on our business opportunities in California. We are currently leasing and supervising the construction of the High Desert Power Project. The High Desert Power Project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that currently qualifies as an operating lease. The project is scheduled for completion in the summer of 2003. As previously discussed in the Events of 2002 section, we have renegotiated our long-term power contract for the sale of the electricity output of the High Desert Power Project to the CDWR. In February 2002, the FASB proposed a new accounting interpretation that potentially would impact the accounting for, but not the cash flows associated with, our High Desert operating lease and the related SPE. Under the proposed interpretation, we may be required to consolidate the SPE in our Consolidated Balance Sheets. We would have recorded approximately $321.8 million of development, construction, and capitalized financing costs as an asset and the related financial obligations as a liability in our Consolidated Balance Sheets had we consolidated this project at March 31, 2002. We discuss our High Desert project in more detail in the Capital Resources section on page 39. Gas Competition - --------------- Currently, no regulation exists for the wholesale price of natural gas as a commodity, and the regulation of interstate transmission at the federal level has been reduced. All BGE gas customers have the option to purchase gas from other suppliers. Regulation by the Maryland PSC - ------------------------------ In addition to electric restructuring which was discussed earlier, regulation by the Maryland PSC influences BGE's businesses. The Maryland PSC determines the rates we can charge our customers for BGE's electric transmission and distribution, and gas businesses. Prior to July 1, 2000, BGE's regulated electric rates consisted primarily of a "base rate" and a "fuel rate." BGE unbundled its electric rates to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate." Base Rate - --------- The base rate is the rate the Maryland PSC allows BGE to charge its customers for the cost of providing them service, plus a profit. BGE has both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes. BGE may ask the Maryland PSC to increase base rates from time to time. The Maryland PSC historically has allowed BGE to increase base rates to recover increased utility plant asset costs and higher operating costs, plus a profit, beginning at the time of replacement. Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates. As a result of the Restructuring Order, BGE's residential electric base rates are frozen until 2006. Electric delivery service rates are frozen until 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. Fuel Rate - --------- Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1, 2000, at which time the fuel rate clause was discontinued. We deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 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 ended October 2001. Effective July 1, 2000, earnings are affected by the changes in the cost of fuel and energy. We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in the Gas Cost Adjustments section on page 36 and in Note 1 of our 2001 Annual Report on Form 10-K. 24 FERC Regulation--Regional Transmission Organizations - ---------------------------------------------------- In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs). On July 12, 2001, FERC provisionally granted RTO status to PJM and ordered it to engage in mediation with the New York ISO and the New England ISO to create a business plan to form one Northeast RTO, using PJM as a platform. After further hearings by FERC, it announced that it is re-evaluating its Order regarding a Northeast RTO. In the meantime, PJM is exploring opportunities to expand into other regions. The creation of large RTOs could benefit our merchant energy business by allowing easier access to transmission and a uniform rate across various regions. In addition, PJM is required to submit a filing by July 1, 2002 addressing implementation of a uniform transmission rate by January 1, 2003. A uniform rate could expose BGE to higher transmission rates. BGE, jointly with other PJM transmission owners, requested rehearing and clarification from FERC on its July 12, 2001 order regarding certain incentive rates, interconnection procedures, and allocations of interconnection costs. FERC has not yet issued an order on this request. Weather - ------- Merchant Energy Business - ------------------------ Weather conditions in the different regions of North America influence the financial results of our merchant energy business. Weather conditions can affect the supply of and demand for electricity and fuels, and changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. Similarly, the demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time. BGE - --- Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Residential sales for our regulated businesses are impacted more by weather than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. However, the Maryland PSC allows us to record a monthly adjustment to our regulated gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the Weather Normalization section on page 36. We measure the weather's effect using "degree days." The measure of degree days for a given day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Cooling degree days result when the average daily actual temperature exceeds the 65 degree baseline. Heating degree days result when the average daily actual temperature is less than the baseline. During the cooling season, hotter weather is measured by more cooling degree days and results in greater demand for electricity to operate cooling systems. During the heating season, colder weather is measured by more heating degree days and results in greater demand for electricity and gas to operate heating systems. We show the number of heating degree days in the quarters ended March 31, 2002 and 2001, and the percentage change in the number of degree days between these periods in the following table: Quarter Ended March 2002 2001 - ------------------------------------------------------- Heating degree days 2,123 2,446 Percent change from prior period (13.2)% Other Factors - ------------- Other factors, aside from weather, impact the demand for electricity and gas in our regulated businesses. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of regulated electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during the periods presented. The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory. Under the Restructuring Order, BGE's electric customers can become delivery service customers only and can purchase their electricity from other sources. We will collect a delivery service charge to recover the fixed costs for the service we provide. The remaining electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas. 25 Results of Operations for the Quarter Ended March 31, 2002 Compared with the - ---------------------------------------------------------------------------- Same Period of 2001 - ------------------- In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Changes in fixed charges and income taxes are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 37. Overview - -------- Net Income - ---------- Quarter Ended March 31, 2002 2001 - --------------------------------------------------------- (In millions) Net Income Before Special Items Included in Operations: Merchant energy $ 30.0 $ 42.4 Regulated electric 29.0 27.7 Regulated gas 27.8 28.7 Other nonregulated (6.8) (5.5) - --------------------------------------------------------- Net Income Before Special Items Included in Operations 80.0 93.3 Special Items Included in Operations: Gains on sale of investments 164.2 10.0 Workforce reduction costs (15.6) -- - --------------------------------------------------------- Net Income Before Cumulative Effect of Change in Accounting Principle 228.6 103.3 Cumulative Effect of Change in Accounting Principle -- 8.5 - --------------------------------------------------------- Net Income $228.6 $111.8 ========================================================= Quarter Ended March 31, 2002 - ---------------------------- Our total net income for the quarter ended March 31, 2002 increased $116.8 million, or $.66 per share, compared to the same period of 2001 mostly because of the following: o We recognized a $163.3 million after-tax gain, or $1.00 per share, on the sale of our investment in Orion as previously discussed in the Events of 2002 section on page 21. o We had higher earnings from our origination and risk management operation. These increases were partially offset by the following: o We experienced milder winter weather in the central Maryland region which impacted all business segments. o We recorded costs of $15.6 million after-tax, or $.09 per share, associated with our corporate-wide workforce reduction program. o The addition of Nine Mile Point Nuclear Station (Nine Mile Point) to the generation fleet reduced net income for this quarter due to the seasonality of the power purchase agreement for this plant. In addition, our other nonregulated businesses recorded the following in the first quarter of 2001 that had a positive impact in that period: o an $8.5 million after-tax, or $.06 per share, gain for the cumulative effect of adopting Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and o gains on the sale of securities of $10.0 million after-tax, or $.06 per share. Earnings per share contributions from all of our business segments are impacted by the dilution resulting from the issuance of 13.2 million of common shares during 2001. In the following sections, we discuss our net income by business segment in greater detail. 26 Merchant Energy Business - ------------------------ Our merchant energy business is exposed to various market risks as discussed further in Item 7. Management's Discussion and Analysis - Market Risk section of our 2001 Annual Report on Form 10-K. We record the financial impacts of these market risks in earnings in different periods depending upon which portion of our merchant energy business they affect. o We record changes in the value of contracts in our origination and risk management operation that are subject to mark-to-market accounting in earnings in the period in which the change occurs. o We record revenues as they are earned and electric fuel and purchased energy costs as they are incurred for contracts subject to accrual accounting. o Prior to the settlement of the anticipated transaction being hedged, we record changes in the value of contracts designated as cash-flow hedges of our generation operations in other comprehensive income to the extent that the hedges are effective. We record the effective portion of hedges in earnings in the period the settlement of the hedged transaction occurs. We record the ineffective portion of such hedges, if any, in earnings in the period in which the change occurs. Mark-to-market accounting requires us to make estimates and assumptions using judgment in determining the fair value of our contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our revenues in the Mark-to-Market Energy Revenues section on page 28. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in the Application of Critical Accounting Policies section on page 20 and in Note 1 of our Annual Report on Form 10-K. As discussed in the Business Environment -- Electric Competition section on page 23, our merchant energy business was significantly impacted by the July 1, 2000 implementation of customer choice in Maryland. At that time, BGE's generating assets became part of our nonregulated merchant energy business, and Constellation Power Source began selling to BGE 100% of the energy and capacity required to meet its standard offer service obligations for the first three years (July 1, 2000 to June 30, 2003) of the transition period. In August 2001, BGE entered into a contract with Constellation Power Source to provide 90% of the energy and capacity required for BGE to meet its standard offer service requirements for the final three years (July 1, 2003 to June 30, 2006) of the transition period. In addition, the merchant energy business revenues include 90% of the competitive transition charges (CTC revenues) BGE collects from its customers and the portion of BGE's revenues providing for nuclear decommissioning costs. Net Income - ---------- Quarter Ended March 31, 2002 2001 - ------------------------------------- -------- ------- (In millions) Revenues $472.3 $345.8 Operating expenses 334.6 226.1 Workforce reduction costs 5.0 -- Depreciation and amortization 56.7 39.6 Taxes other than income taxes 20.6 11.2 - ------------------------------------- -------- ------- Income from Operations $ 55.4 $ 68.9 ===================================== ======== ======= Net Income $ 27.0 $ 42.4 ===================================== ======== ======= Net Income Before Special Items Included in Operations $ 30.0 $ 42.4 Workforce reduction costs (3.0) -- - ------------------------------------- -------- ------- Net Income $ 27.0 $ 42.4 ===================================== ======== ======= Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Revenues - -------- Merchant energy revenues increased $126.5 million during the quarter ended March 31, 2002 compared to the same period of 2001 mostly due to: o higher revenues from other sales of generation, including new peaking facilities and Nine Mile Point, o higher mark-to-market energy revenues, and o the re-designation of our Texas load-serving business to non-trading as discussed in more detail on page 32. These increases were partially offset by a decrease in revenues related to supplying BGE's standard offer service requirements. We discuss these revenue changes in more detail below. Revenues from BGE Standard Offer Service - ---------------------------------------- The revenues from BGE's Standard Offer Service requirements decreased by $10.3 million, including CTC and decommissioning revenues that decreased $4.4 million, due to milder winter weather in central Maryland. Other Generation Revenues - ------------------------- Other generation revenues increased $90.1 million during the quarter ended March 31, 2002 compared to the same period of 2001 primarily due to: o revenues of $92.4 million from Nine Mile Point that was acquired in November 2001, o a $23.4 million increase related to the re-designation of the Texas load-serving business to non-trading from mark-to-market energy revenues, and 27 o revenues of $3.4 million from peaking facilities that commenced operations during mid-summer 2001. These increases were partially offset by $21.4 million of lower sales of power from our Baltimore plants in excess of that required to serve BGE's standard offer service requirements compared to 2001. These lower sales were due primarily to the extended outage at Calvert Cliffs in order to replace the steam generators at Unit 1 and lower generation from our coal plants. In addition, in March 2001, our generation operation recognized a $9.5 million gain on the sale of a project under development in the PJM region that had a positive impact in that period. Under the Restructuring Order, larger industrial customers have available standard offer service until June 30, 2002. Beginning in July 2002, approximately 1,000 megawatts of industrial customer load will move from BGE's standard offer service to market-based rates. As a result, our merchant energy business will have an increasing amount of generating capacity that will be sold at wholesale market rates and thus be subject to future changes in wholesale electricity prices. California Power Purchase Agreements - ------------------------------------ Our generation operation has $277.9 million invested in 13 operating power projects of which our ownership percentage represents 137 megawatts of electricity that are sold to PGE and SCE in California under power purchase agreements called SO4 agreements. Under these agreements, the projects supply electricity to these utilities at variable rates. Revenues from these projects were about the same compared to the same period in 2001. While California power prices were significantly lower in the first quarter of 2002 compared to the same period of 2001, this was offset by credit reserves established for our exposure in California during the first quarter of 2001 that had a negative impact in that period. These reserves were subsequently reversed in the first quarter of 2002 as discussed below. 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 March 31, 2002, we received $28 million of the $45 million for unpaid power sales plus interest, which included payment of 100% of the SCE outstanding balance. We expect to collect the remaining outstanding balance plus interest from PGE within the next year. Accordingly, we reversed all of our credit reserves that totaled $9.1 million. As previously discussed in the Business Environment-Other States section on page 23, the projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original SO4 contracts. We expect the revenues from these projects to be lower during the remainder of 2002 compared to 2001. Mark-to-Market Energy Revenues - ------------------------------ Mark-to-market energy revenues include net gains and losses from Constellation Power Source origination and risk management activities for which the mark-to-market method of accounting is required by Emerging Issues Task Force Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. We discuss the mark-to-market method of accounting and Constellation Power Source's activities in more detail in the Application of Critical Accounting Policies section on page 20 and in Note 1 in our 2001 Annual Report on Form 10-K. As a result of the nature of its operations and the use of mark-to-market accounting for certain activities, Constellation Power Source's revenues and earnings will fluctuate. We cannot predict these fluctuations, but the impact on our revenues and earnings could be material. We discuss our market risk in more detail in Item 7. Management's Discussion and Analysis - Market Risk section in our 2001 Annual Report on Form 10-K. The primary factors that cause fluctuations in our revenues and earnings are: o the number, size, and profitability of new transactions, o the magnitude and volatility of changes in commodity prices and interest rates, and o the number and size of our open commodity and derivative positions. Mark-to-market energy revenues were as follows: Quarter Ended March 31, 2002 2001 - ---------------------------------- ---------- --------- (In millions) New origination transactions $ 9.5 $37.9 Risk management activities Realized 20.9 (30.6) Unrealized 33.4 4.7 - ---------------------------------- ---------- --------- Total risk management activities 54.3 (25.9) - ---------------------------------- ---------- --------- Total $63.8 $12.0 ================================== ========== ========= Revenues from new origination transactions represent the initial unrealized fair value of new wholesale energy transactions at the time of contract execution. Risk management revenues represent both realized and unrealized gains and losses from changes in the value of our entire portfolio. We discuss the changes in origination and risk management revenues below. Constellation Power Source's mark-to-market revenues are influenced by our focus on serving the full electric energy and capacity requirements of electric utility customers. Providing utilities' full energy and capacity requirements requires greater ownership of, or contractual access to, power generating facilities, as opposed to merely standard products obtainable in liquid trading markets. 28 The relationship of the realized portion of revenue to total mark-to-market energy revenue in the table on the previous page reflects the nature of the origination transactions which Constellation Power Source has executed. A significant portion of these contracts provide for Constellation Power Source to serve customers' energy requirements at fixed prices that are lower in the early years of the contracts but that are expected to provide increased margins and cash flows over the remaining terms of the contracts. We discuss the settlement terms of our contracts on page 30. Mark-to-market energy revenues increased $51.8 million during the quarter ended March 31, 2002 compared to the same period of 2001 mostly because of net gains from risk management activities, partially offset by lower revenues from new origination transactions. The increase in net gains from risk management activities is primarily due to increases in future power prices in 2002 compared to decreases in power prices in the same period of 2001. The decrease in origination revenue reflects fewer individually significant transactions in 2002 as compared to the same period of 2001. Constellation Power Source's mark-to-market energy assets and liabilities are comprised of a combination of 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 other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. Mark-to-market energy assets and liabilities consisted of the following: March 31, December 31, 2002 2001 - ---------------------------------- ---------- ------------ (In millions) Current Assets $ 637.4 $ 398.4 Noncurrent Assets 853.0 1,819.8 - ---------------------------------- ---------- ------------ Total Assets 1,490.4 2,218.2 - ---------------------------------- ---------- ------------ Current Liabilities 575.6 323.3 Noncurrent Liabilities 549.7 1,476.5 - ---------------------------------- ---------- ------------ Total Liabilities 1,125.3 1,799.8 - ---------------------------------- ---------- ------------ Net mark-to-market energy asset $ 365.1 $ 418.4 ================================== ========== ============ Following are the primary sources of the change in net mark-to-market energy asset during the quarter ended March 31, 2002: Change in Net Mark-to-Market Energy Asset - ------------------------------------------ ----------------- (In millions) Fair value at December 31, 2001 $418.4 Changes in fair value recorded as revenues New origination transactions $9.5 -------- Unrealized risk management revenues: Contracts settled (20.9) Changes in valuation techniques 0.5 Unrealized changes in fair value 53.8 -------- Total unrealized risk management revenues $33.4 -------- Total changes in fair value recorded as revenues 42.9 Changes in fair value recorded as operating expenses 0.3 Net change in premiums on options (37.1) Texas contracts re-designated as non-trading (63.3) Other changes in fair value 3.9 - ------------------------------------------- ---------------- Fair value at March 31, 2002 $365.1 ============================================================ New origination transactions represent the initial unrealized fair value at the time these contracts are executed. Changes in valuation techniques represent improvements in the models used to value our portfolio to reflect more accurately the economic value of our contracts. Unrealized changes in fair value represent the change in value of our unrealized net mark-to-market energy asset due to changes in commodity prices, the volatility of options on commodities, the time value of options, and net changes in valuation allowances. Changes in fair value recorded as operating expenses represent accruals for future incremental expenses in connection with servicing origination transactions. While these accruals are recorded as part of the fair value of the net mark-to-market energy asset, they are reflected in the income statement as expenses rather than revenue. The net change in premiums on options reflects a net increase in options sold during 2002. We record premiums on options purchased as an increase in the net mark-to-market energy asset and premiums on options sold as a decrease in the net mark-to-market energy asset. Prior to 2001, we had entered into purchased option and energy tolling contracts in connection with serving our energy sales contracts. The option and tolling contracts, by their nature, exposed us to changes in the volatility of energy prices. During the quarter ended March 31, 2002, we sold options to reduce our exposure to option volatility. We discuss our re-designation of the Texas load-serving activities as non-trading in more detail on page 32. 29 The settlement term of the net mark-to-market energy asset and sources of fair value as of March 31, 2002 are as follows:
Settlement Term ----------------------------------------------------------------------------------------------- Total 2008 - Fair 2002 2003 2004 2005 2006 2007 2009 Thereafter Value --------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ---------- (In millions) Prices provided by external sources $98.7 $38.3 $(41.7) $(16.6) $(57.2) $ (2.1) $ (3.2) $(2.1) $ 14.1 Prices based on models (66.3) (22.8) 83.0 77.2 131.4 44.2 94.6 9.7 351.0 --------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ---------- Total net mark-to-market energy asset $32.4 $15.5 $ 41.3 $ 60.6 $ 74.2 $ 42.1 $ 91.4 $ 7.6 $365.1 ===================== ========== ======== ========= ========== ========= ========== ========== =========== ==========
The portion of the net mark-to-market energy asset as of March 31, 2002 that was valued using prices provided by external sources decreased compared to the level that was similarly valued as of December 31, 2001. Two primary factors contributed to the decrease: o the re-designation of our Texas load-serving business as non-trading as described on page 32, which resulted in a reduction of the net mark-to-market energy asset, most of which was valued using prices available from external sources, and o a reduction in the portion of our New England load-serving business for which prices are available from external sources due to a significant decrease in market liquidity and available pricing information in New England as a result of pending market changes. Pending changes in the New England market have reduced market liquidity and pricing information compared to the information that was available as of December 31, 2001. Because of the long-term nature of our load-serving contracts and supply arrangements and changes in this market, a greater proportion of these contracts extend for terms for which market prices are not presently available from external sources. The New England load-serving business consists primarily of contracts to serve the full energy and capacity requirements of electric distribution utilities and associated power purchase agreements to supply our customers' requirements. While these contracts are currently included in our trading activities portfolio that is subject to mark-to-market accounting under EITF 98-10, we manage this business primarily to assure profitable delivery of customers' energy requirements rather than as a traditional trading activity. The following table presents the settlement terms of our net mark-to-market energy asset excluding contracts associated with the New England load-serving business.
Settlement Term Excluding New England Load-Serving Business ----------------------------------------------------------------------------------------------- Total 2008 - Fair 2002 2003 2004 2005 2006 2007 2009 Thereafter Value --------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ---------- (In millions) Prices provided by external sources $60.4 $45.4 $(3.1) $17.3 $ 8.7 $(2.5) $(4.9) $(2.2) $119.1 Prices based on models 2.2 7.3 (2.8) 8.0 36.3 23.9 40.0 17.7 132.6 --------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ---------- Total $62.6 $52.7 $(5.9) $25.3 $45.0 $21.4 $35.1 $15.5 $251.7 ===================== ========== ======== ========= ========== ========= ========== ========== =========== ==========
30 Constellation Power Source manages its risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year). Consistent with our risk management practices, we have presented the information in the tables on the previous page based upon the ability to obtain reliable prices for components of the risks in our contracts from external sources rather than on a contract-by-contract basis. Thus, the portion of long-term contracts that is valued using external price sources is classified in the same caption as other shorter-term transactions that settle in the same period. This presentation is consistent with how we manage our risk, and we believe it provides the best indication of the basis for the valuation of our portfolio. Since we manage our risk on a portfolio basis rather than contract-by-contract, it is not practicable to determine separately the portion of long-term contracts that is included in each valuation category. We describe the commodities, products, and delivery periods included in each valuation category in detail below. The amounts for which fair value is determined using prices provided by external sources represent the portion of forward, swap, and option contracts for which price quotations are available through brokers or over-the-counter transactions. The term for which such price information is available varies by commodity, region, and product. The fair values included in this category are the following portions of our contracts: o forward purchases and sales of electricity during peak hours for delivery terms from 2003 through 2010, depending upon the region, o forward purchases and sales of electricity during off-peak hours for delivery terms from 2003 through 2006, depending upon the region, o options for the purchase and sale of electricity during peak hours for delivery terms through 2003, depending upon the region, o forward purchases and sales of electric capacity for delivery terms through 2003, depending upon the region, o forward purchases and sales of natural gas for delivery terms through 2006, o forward purchase and sales of oil for delivery terms through 2003, o options for the purchase and sale of natural gas for delivery terms through 2006, and o options for the purchase and sale of oil for delivery terms through 2003. The remainder of the net mark-to-market energy asset is valued using models. The portion of contracts for which such techniques are used includes standard products for which external prices are not available and customized products which are valued using modeling techniques to determine expected future market prices, contract quantities, or both. Modeling techniques include estimating the present value of cash flows based up on underlying contractual terms and incorporate, where appropriate, option pricing models and statistical and simulation procedures. Inputs to the models include observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlation of energy commodity prices, contractual volumes, and estimated volumes for requirements contracts. Additionally, we incorporate counterparty-specific credit quality and factors for market price uncertainty and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates. The electricity, fuel, and other energy contracts held by Constellation Power Source have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, the majority of contracts used in the origination and risk management operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that readily can be liquidated in their entirety through an exchange or other market mechanism. Consequently, Constellation Power Source and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves. Consistent with our risk management practices, the amounts shown in the tables on the previous page as being valued using prices from external sources include the portion of long-term contracts for which we can obtain reliable prices from external sources. The remaining portions of these long-term contracts are shown in the tables as being valued using models. In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the tables. However, based upon the nature of the origination and risk management operation, we 31 expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. We do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total. The fair values in the tables represent expected future cash flows based on the level of forward prices and volatility factors as of March 31, 2002. These amounts do not represent the contractual maturities and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. 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. Re-designation of Texas Business - -------------------------------- During February 2002, we re-designated our Texas load-serving business from trading to non-trading (accrual accounting) under EITF 98-10. As a result of the changes in our organization and senior management in late 2001, including the cancellation of business separation and termination of the power business services agreement with Goldman Sachs, we re-evaluated our load-serving activities. We manage these activities as a physical delivery business rather than a trading business. In Texas, we serve our customers' energy requirements using physically delivering power purchase agreements and our Rio Nogales plant, which is currently undergoing start-up activities and is scheduled to be placed in service in the summer of 2002. Further, changes in the Texas market in mid-February 2002 significantly reduced trading activity and the ability to manage load-serving transactions through trading activities. Based upon these factors, we began to manage our Texas load-serving activities as a physical delivery business separate from our trading activities and re-designated this operation as non-trading effective February 15, 2002. We believe that this designation more accurately reflects the substance of our Texas load-serving physical delivery activities. At the time of this change in designation, we reclassified the fair value of load-serving contracts and physically delivering power purchase agreements in Texas from "Mark-to-market energy assets and liabilities" to "Other assets" and "Other deferred credits and other liabilities." The contracts reclassified consisted of gross assets of $78 million and gross liabilities of $15 million, or a net asset of $63 million. Beginning February 15, 2002, the results of our Texas load-serving business are included in "Nonregulated revenues" on a gross basis as power is delivered to our customers. These revenues totaled $23.4 million for the period February 15, 2002 through March 31, 2002. Prior to the date of re-designation, the results of these activities were reported on a net basis as part of mark-to-market energy revenues included in "Nonregulated revenues." Mark-to-market energy revenues for the Texas trading activities were a net loss of $1.2 million for the portion of the first quarter of 2002 prior to the designation as non-trading and a net loss of $19.0 million for the first quarter of 2001. The change in designation of our Texas load-serving business will not impact our cash flows. However, because future power sales revenues and costs from this business will be reflected in our Consolidated Statements of Income as part of "Nonregulated revenues" when power is delivered and "Operating expenses" when the costs are incurred, this re-designation generally will delay the recognition of earnings from this business in the future compared to what we would have recognized under mark-to-market accounting. Earnings initially will be lower because we will record the margin on new transactions as power is delivered to customers over the contract term rather than in full at the inception of each new contract. Additionally, we also expect lower earnings volatility for this portion of our business because unrealized changes in the fair value of Texas load-serving contracts will no longer be recorded as revenue at the time of the change under mark-to-market accounting as is required for trading activities under EITF 98-10. 32 Operating Expenses - ------------------ Merchant energy operating expenses increased $108.5 million during the quarter ended March 31, 2002 compared to the same period of 2001 mostly because of the following: o Operations and maintenance costs increased $62.4 million and fuel and purchased energy costs increased $1.5 million. These increases reflect the operations of the new peaking facilities and Nine Mile Point, an increase in purchased energy to supply BGE Standard Offer Service due to the extended outage at Calvert Cliffs and lower generation at our coal plants, and higher coal prices. These increases were offset by the lower generation and lower purchased energy prices due to milder winter weather in the central Maryland region compared to the same period of 2001. However, we expect to incur additional costs in the future to operate our coal generating facilities due to higher prices. o A $24.6 million increase related to the re-designation of the Texas load-serving business to non-trading from mark-to-market energy revenues. o Origination and risk management operating expenses increased $25.6 million as a result of the growth of this operation. These increased costs were partially offset by the absence of fees paid to Goldman Sachs due to the termination of the power business services agreement in October 2001. The Goldman Sachs fees were $6.5 million in the first quarter of 2001. As a result of the events of September 11, 2001, the Nuclear Regulatory Commission (NRC) issued regulations that require U.S. nuclear power plants to provide for additional security measures. In order to fully comply with these regulations, we expect to incur additional operating expenses, as well as, costs for capital improvements at each of our two nuclear power plant sites, Calvert Cliffs and Nine Mile Point. Our nuclear plants are taking all appropriate steps to ensure compliance with these regulations. Extended Nuclear Outages - ------------------------ Our merchant energy business began an extended outage at Unit 1 of Calvert Cliffs during the first quarter of 2002 to replace the steam generators. We expect the outage to extend into June 2002. As previously discussed in this section, our merchant energy business had lower revenues and higher operating costs due to the extended outage at Calvert Cliffs. Calvert Cliffs also will replace the steam generators for Unit 2 during the 2003 refueling outage. As a result of the extended outages, we expect lower annual revenues and higher annual operating costs for each extended outage. Workforce Reduction Costs - ------------------------- As previously discussed in the Events of 2002 section on page 21, our merchant energy business recognized $5.0 million of expenses associated with our workforce reduction efforts. As a result of our workforce reduction efforts, our merchant energy business expects to generate annual savings of approximately $24 million. Depreciation and Amortization Expense - ------------------------------------- Merchant energy depreciation and amortization expense increased $17.1 million in the quarter ended March 31, 2002 compared to the same period of 2001 mostly because of the depreciation and amortization associated with the new peaking facilities and Nine Mile Point. Taxes Other than Income Taxes - ----------------------------- Merchant energy taxes other than income taxes increased $9.4 million in the quarter ended March 31, 2002 compared to the same period of 2001 mostly because of taxes other than income taxes associated with Nine Mile Point. 33 Regulated Electric Business - --------------------------- As previously discussed, our regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice. These changes include BGE's generating assets and related liabilities becoming part of our nonregulated merchant energy business on that date. Net Income - ---------- Quarter Ended March 31, 2002 2001 - --------------------------------------------------------- (In millions) Electric revenues $460.4 $492.3 Electric fuel and purchased energy 240.5 265.8 Operations and maintenance 60.8 61.8 Workforce reduction costs 20.9 -- Depreciation and amortization 43.8 43.4 Taxes other than income taxes 34.7 35.9 - --------------------------------------------------------- Income from Operations $ 59.7 $ 85.4 ========================================================= Net Income $ 16.4 $ 27.7 ========================================================= Net Income Before Special Items Included in Operations $29.0 $27.7 Workforce reduction costs (12.6) -- - --------------------------------------------------------- Net Income $16.4 $27.7 ========================================================= Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Electric Revenues - ----------------- The changes in electric revenues in 2002 compared to 2001 were caused by: Quarter Ended March 31, 2002 vs. 2001 - -------------------------------------------------------- (In millions) Electric system sales volumes $(16.0) Rates 2.2 Fuel rate surcharge (14.8) - -------------------------------------------------------- Total change in electric revenues from electric system sales (28.6) Other (3.3) - -------------------------------------------------------- Total change in electric revenues $(31.9) ======================================================== Electric System Sales Volumes - ----------------------------- "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. As part of the Restructuring Order, the rates received from customers under the standard offer service increase over the transition period as discussed further in the Business Environment--Electric Competition section beginning on page 23. The percentage changes in our electric system sales volumes, by type of customer, in 2002 compared to 2001 were: Quarter Ended March 31, 2002 vs. 2001 - ------------------------------------------------------- Residential (5.9)% Commercial 0.1 Industrial (1.1) During the quarter ended March 31, 2002, we sold less electricity to residential customers compared to the same period of 2001 due to milder weather. We sold about the same amount of electricity to commercial and industrial customers. Rates - ----- Effective July 1, 2000, BGE unbundled its rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and taxes. BGE's rates also were frozen in total except for the implementation of a residential base rate reduction totaling approximately $54 million annually. In addition, 90% of the CTC revenues BGE collects and the portion of its revenues providing for decommissioning costs, are included in revenues of the merchant energy business. Rate revenues for the quarter ended March 31, 2002 increased slightly compared to the same period of 2001 due to the increase in the standard offer service rate that BGE charges its customers. This is partially offset by a decrease in the 10% portion of the CTC rate received from customers that is retained by BGE. Fuel Rate Surcharge - ------------------- 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 discuss this further in the Electric Fuel Rate Clause section on the next page. 34 Electric Fuel and Purchased Energy Expenses - ------------------------------------------- Quarter Ended March 31, 2002 2001 - --------------------------------------------------------- (In millions) Actual costs $240.5 $251.3 Net recovery of costs under electric fuel rate clause -- 14.5 - --------------------------------------------------------- Total electric fuel and purchased energy expenses $240.5 $265.8 ========================================================= Actual Costs - ------------ As discussed in the Business Environment--Electric Competition section on page 23, BGE transferred its generating assets to, and began purchasing substantially all of the energy and capacity required to provide electricity to standard offer service customers from, the merchant energy business. Our actual costs of fuel and purchased energy for the quarter ended March 31, 2002 compared to the same period of 2001 were lower mostly because BGE purchased less energy due to milder weather in the central Maryland region at a lower price. Electric Fuel Rate Clause - ------------------------- Prior to July 1, 2000, we deferred (included as an asset or liability on the Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate in a given period. Effective July 1, 2000, the fuel rate clause was discontinued under the terms of the Restructuring Order. 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 - ------------------------- As previously discussed in the Events of 2002 section on page 21, BGE's electric business recognized $20.9 million of expenses associated with our workforce reduction efforts. As a result of our workforce reduction efforts, BGE's electric business expects to generate annual savings of approximately $33 million. Other Electric Operating Expenses - --------------------------------- Regulated other electric operating expenses were about the same for the quarter ended March 31, 2002 compared to the same period of 2001. Regulated Gas Business - ---------------------- Net Income - ---------- Quarter Ended March 31, 2002 2001 - --------------------------------------------------------- (In millions) Gas revenues $223.3 $357.6 Gas purchased for resale 124.3 252.9 Operations and maintenance 23.7 24.6 Depreciation and amortization 12.7 14.3 Taxes other than income taxes 9.3 10.1 - --------------------------------------------------------- Income from Operations $ 53.3 $ 55.7 ========================================================= Net Income $ 27.8 $ 28.7 ========================================================= Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Net income from the regulated gas business decreased during the quarter ended March 31, 2002 compared to the same period of 2001 mostly due to a decrease in the sharing mechanism under our gas cost adjustment clauses. All BGE customers have the option to purchase gas from other suppliers. To date, customer choice has not had a material effect on our, and BGE's, financial results. Gas Revenues - ------------ The changes in gas revenues in 2002 compared to 2001 were caused by: Quarter Ended March 31, 2002 vs. 2001 - -------------------------------------------------------- (In millions) Gas system sales volumes $ (11.3) Base rates (1.8) Weather normalization 8.8 Gas cost adjustments (89.2) - -------------------------------------------------------- Total change in gas revenues from gas system sales (93.5) Off-system sales (39.8) Other (1.0) - -------------------------------------------------------- Total change in gas revenues $(134.3) ======================================================== 35 Gas System Sales Volumes - ------------------------ The percentage changes in our gas system sales volumes, by type of customer, in 2002 compared to 2001 were: Quarter Ended March 31, 2002 vs. 2001 - --------------------------------------------------------- Residential (13.0)% Commercial 3.5 Industrial (1.5) During the quarter ended March 31, 2002, we sold less gas to residential customers compared to the same period of 2001 mostly due to milder winter weather and lower usage per customer partially offset by an increased number of customers. We sold more gas to commercial customers mostly due to higher usage per customer. We sold less gas to industrial customers mostly because of lower usage by industrial customers due to their lower business needs related to the general downturn in the economy and a decreased number of customers. Base Rates - ---------- Base rate revenues decreased for the quarter ended March 31, 2002 compared to the same period of 2001 mostly because of a decrease in the rate approved by the Maryland PSC associated with the energy conservation surcharge program. Weather Normalization - --------------------- The Maryland PSC allows us to record a monthly adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues are based on weather that is considered "normal" for the month and, therefore, are not affected by actual weather conditions. Gas Cost Adjustments - -------------------- We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 of our 2001 Annual Report on Form 10-K. However, 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. During the quarter ended March 31, 2002, the shareholders' portion decreased $1.8 million compared to the same period of 2001. Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales and are included in gas system sales volumes. During the quarter ended March 31, 2002, gas cost adjustment revenues decreased compared to the same period of 2001 mostly because we sold less gas at a lower price. Off-System Sales - ---------------- Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings. During the quarter ended March 31, 2002, revenues from off-system gas sales decreased compared to the same period of 2001 mostly because we sold less gas off-system at a lower price. Gas Purchased For Resale Expenses - --------------------------------- Actual costs include the cost of gas purchased for resale to our customers and for off-system sales. Actual costs do not include the cost of gas purchased by delivery service customers. During the quarter ended March 31, 2002, our gas costs decreased compared to the same period of 2001 because we bought less gas at a lower price. Other Gas Operating Expenses - ---------------------------- During the quarter ended March 31, 2002, other gas operating expenses decreased compared to the same period of 2001 mostly because of timing of operating expenses, lower depreciable gas plant in service, and lower gross receipts taxes associated with lower revenues. As a result of our workforce reduction efforts, BGE's gas business expects to generate annual savings of approximately $15 million. 36 Other Nonregulated Businesses - ----------------------------- Net Income - ---------- Quarter Ended March 31, 2002 2001 - ------------------------------------------------------------ (In millions) Revenues $120.4 $213.7 Operating expenses 116.4 197.9 Gains on sale of investments 257.1 16.6 Depreciation and amortization 3.9 6.3 Taxes other than income taxes 1.0 1.2 - ------------------------------------------------------------ Income from Operations $256.2 $ 24.9 ============================================================ Net Income Before Cumulative Effect of Change in Accounting Principle $157.4 $ 4.5 Cumulative Effect of Change in Accounting Principle -- 8.5 - ------------------------------------------------------------ Net Income $157.4 $ 13.0 ============================================================ Net Loss Before Special Items Included in Operations (6.8) (5.5) Gains on sale of investments 164.2 10.0 - ------------------------------------------------------------ Net Income Before Cumulative Effect of Change in Accounting Principle $157.4 $ 4.5 Cumulative Effect of Change in Accounting Principle -- 8.5 - ------------------------------------------------------------ Net Income $157.4 $ 13.0 ============================================================ Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. During the quarter ended March 31, 2002, earnings from our other nonregulated businesses increased compared to the same period of 2001 mostly because of the recognition of a $163.3 million after-tax gain on the sale of our investment in Orion as previously discussed in the Events of 2002 section on page 21. This gain was partially offset by gains on the sale of securities in the first quarter of 2001 that had a positive impact in that period and lower net income before special items from our financial investments operation due to declining equity values. In addition, our other nonregulated businesses recorded an $8.5 million after-tax gain for the cumulative effect of adopting Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, in the first quarter of 2001 that had a positive impact in that period. As previously discussed in our 2001 Annual Report on Form 10-K, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. These assets include approximately 1,300 acres of land holdings in various stages of development located in seven sites in the central Maryland region, an operating waste water treatment plant located in Anne Arundel County, Maryland, all of our 18 senior-living facilities, and certain international power projects. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses. In addition, we initiated a liquidation program for our financial investments operation and expect to sell substantially all of our investments in this operation by the end of 2003. Our remaining projects are partially or substantially developed. Our strategy is to hold and in some cases further develop these projects to increase their value. However, if we were to sell these projects in the current market, we may have losses that could be material, although the amount of the losses is hard to predict. Consolidated Nonoperating Income and Expenses - --------------------------------------------- Fixed Charges - ------------- During the quarter ended March 31, 2002, total fixed charges decreased compared to the same period of 2001 mostly because of the repayment of debt and lower short-term interest rates. Income Taxes - ------------ During the quarter ended March 31, 2002, our total income taxes increased compared to the same period of 2001 mostly because of the gain on the sale of our investment in Orion. 37 Financial Condition - ------------------- Cash Flows - ---------- Cash provided by operations was $434.9 million for the quarter ended March 31, 2002 compared to $194.7 million in 2001. For the quarter ended March 31, 2002, cash provided by investing activities was $366.1 million compared to cash used in investing activities of $278.9 million in 2001. The increase during 2002 was primarily due to the sale of Orion and COPT that generated $555.4 million in cash proceeds, as well as, a decrease in capital spending due to the termination of all planned development projects. Cash provided by financing activities for the quarter ended March 31, 2002 was $168.7 million compared to $420.1 million in 2001. The decrease during 2002 was primarily due to the issuance of common stock in 2001, partially offset by more debt issuance proceeds than debt repayments and net maturities of short-term borrowings in 2002. Security Ratings - ---------------- Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities. The better the rating, the lower the cost of the securities to each company when they sell them. The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include cash flows, liquidity, and the amount of debt as a component of total capitalization. All Constellation Energy and BGE credit ratings have stable outlooks. At the date of this report, our credit ratings were as follows: Standard Moody's & Poors Investors Fitch- Rating Group Service Ratings - ----------------------------------------------------------- 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- Available Sources of Funding - ---------------------------- As previously discussed in our 2001 Annual Report on Form 10-K, we decided to sell certain non-core assets to focus on our core strategies. We expect to use the proceeds from these sales to reduce our debt and fund our merchant energy business. In addition, we issued $1.8 billion of debt in March 2002. We continuously monitor our liquidity requirements and believe that our facilities and access to the capital markets provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding in more detail below. Constellation Energy - -------------------- In addition to the $1.8 billion of debt issued in March 2002, Constellation Energy has a commercial paper program where it can issue short-term notes to fund its subsidiaries. To support its commercial paper program, Constellation Energy maintains two 364-day revolving credit agreements totaling $1.1 billion maturing in June 2002, as well as, a $188.5 million multi-year revolving credit facility. Two of these facilities can also issue letters of credit. As of March 31, 2002, Constellation Energy had $335.4 million in outstanding letters of credit and $191.1 million of outstanding commercial paper which results in approximately $742 million of unused credit facilities. Constellation Energy is currently in the process of refinancing its two 364-day revolving credit agreements and anticipates replacing them with a 364-day facility and a multi-year facility. Constellation Energy also has access to interim lines of credit as required from time to time to support its outstanding commercial paper. BGE - --- BGE maintains $168.0 million in annual committed bank lines of credit and has two bank revolving credit agreements to support the commercial paper program. The first is a $25 million multi-year agreement which expires June 2003, and the other is a $50 million 364-day agreement that expires in late 2002. As of March 31, 2002, BGE had no outstanding commercial paper, which results in $243.0 million in unused credit facilities. BGE also has access to interim lines of credit as required from time to time to support its outstanding commercial paper and maintains a program to sell receivables up to $25 million. Other Nonregulated Businesses - ----------------------------- BGE Home Products & Services maintains a program to sell receivables up to $50 million. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs, which will expire in September 2002. If we can get a reasonable value for our remaining real estate projects and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. 38 Capital Resources - ----------------- Our business requires a great deal of capital. Our estimated annual amounts for the years 2002 and 2003 are shown in the table below. We will continue to have cash requirements for: o working capital needs including the payments of interest, distributions, and dividends, o capital expenditures, and o the retirement of debt and redemption of preference stock. Capital requirements for 2002 and 2003 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including: o regulation, legislation, and competition, o BGE load requirements, o environmental protection standards, o the type and number of projects selected for construction or acquisition, o the effect of market conditions on those projects, o the cost and availability of capital, and o the availability of cash from operations. Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 43. Calendar Year Estimates 2002 2003 -------------------------------------------------- (In millions) Nonregulated Capital Requirements: Merchant Energy Construction program $152 $ -- Steam generators 91 65 Environmental controls 69 16 Continuing requirements (including nuclear fuel) 243 199 -------------------------------------------------- Total Merchant Energy 555 280 capital requirements Other Nonregulated capital requirements 39 34 -------------------------------------------------- Total Nonregulated capital requirements 594 314 -------------------------------------------------- Utility Capital Requirements: Regulated electric 174 174 Regulated gas 56 56 -------------------------------------------------- Total Utility capital requirements 230 230 -------------------------------------------------- Total capital requirements $824 $544 ================================================== Capital Requirements - -------------------- Merchant Energy Business - ------------------------ Our merchant energy business will require additional funding for power projects under construction and growing its origination and risk management operation. These capital requirements include: o Construction expenditures for approximately 2,900 megawatts of natural gas-fired peaking and combined cycle production facilities in various regions of North America under construction. o Cost for replacing the steam generators at Calvert Cliffs. In March 2000, we received a license extension from the NRC that extends Calvert Cliffs' operating licenses to 2034 for Unit 1 and 2036 for Unit 2. Replacement of the steam generators will allow us to operate these units through our operating license periods. The 2002 steam generator replacement for Unit 1 is underway and is expected to be completed by the beginning of June 2002. We expect the 2003 steam generator replacement to occur during the 2003 refueling outage for Unit 2. o Construction expenditures for improvements to generating plants, including costs of complying with Environmental Protection Agency (EPA), Maryland and Pennsylvania nitrogen oxides (NOx) emissions regulations. We discuss the NOx regulations and timing of expenditures in the Environmental Matters section of the Notes to the Consolidated Financial Statements beginning on page 13. The above table does not include the financing for the High Desert 750 megawatt gas-fired generation project in California, which is under an operating lease with a term through February 2006. As an operating lease, we do not record any assets or debt associated with the project in our Consolidated Balance Sheets. We are leasing the project and supervising its construction. 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. Under certain circumstances, 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 March 31, 2001, the outstanding lease balance plus other committed expenses was $383.2 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. 39 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. Regulated Electric and Gas - -------------------------- Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities. Funding for Capital Requirements - -------------------------------- Merchant Energy Business - ------------------------ Funding for the expansion of our merchant energy business is expected from internally generated funds, commercial paper, issuances of long-term debt and equity, leases, and other financing instruments issued by Constellation Energy and its subsidiaries. The projects that our merchant energy business develop typically require substantial capital investment. Most of the projects recently constructed or currently under construction are funded through corporate borrowings by Constellation Energy. Certain other projects in which we have an interest are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized by interests in the physical assets, major project contracts and agreements, cash accounts and, in some cases, the ownership interest in that project. Longer term, we expect to fund our growth and operating objectives with a mixture of debt and equity with an overall goal of maintaining an investment grade credit profile. BGE - --- Funding for utility capital expenditures is expected from internally generated funds. During 2002 and 2003, we expect our regulated utility business to provide at least 140% of the cash needed to meet the capital requirements for its operations, excluding cash needed to retire debt. If necessary, additional funding may be obtained from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Constellation Energy. Other Nonregulated Businesses - ----------------------------- Funding for our other nonregulated businesses is expected from internally generated funds, commercial paper issuances, issuances of long-term debt of Constellation Energy, and sales of assets. BGE Home Products & Services can continue to fund capital requirements through sales of receivables. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs, which will expire in September 2002. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss our remaining real estate projects and market conditions in the Other Nonregulated Businesses section on page 37. Committed Amounts - ----------------- Our total contractual and contingent obligations as of March 31, 2002 are shown in the following table: Payments/Expiration -------------------------------------------- 2003- 2005- There- 2002 2004 2006 after Total - --------------------------------------------------------------- (In millions) Contractual Obligations - ----------------------- Short-term borrowings $ 199.2 $ -- $ -- $ -- $ 199.2 Nonregulated long-term debt 84.9 209.8 456.8 2,144.1 2,895.6 BGE long-term debt 319.8 441.0 511.8 947.7 2,220.3 BGE preference stock -- 130.0 60.0 -- 190.0 Fuel and transportation 241.2 352.0 81.9 12.8 687.9 Purchased capacity and energy 14.6 26.2 26.5 89.2 156.5 Operating leases 7.6 63.7 51.2 127.9 250.4 Capital and loan commitments * 50.7 0.8 -- -- 51.5 - --------------------------------------------------------------- Total contractual obligations 918.0 1,223.5 1,188.2 3,321.7 6,651.4 - --------------------------------------------------------------- Contingent Obligations - ---------------------- Letters of credit 332.6 2.8 -- -- 335.4 Guarantees, net** 484.4 53.0 686.0 209.4 1,432.8 - --------------------------------------------------------------- Total contingent obligations 817.0 55.8 686.0 209.4 1,768.2 - --------------------------------------------------------------- Total obligations $1,735.0 $1,279.3 $1,874.2 $3,531.1 $8,419.6 =============================================================== *Amounts are included for applicable periods in our capital requirements table on page 39. ** Guarantees in the above table are shown net of liabilities recorded at March 31, 2002 in our Consolidated Balance Sheets. While we included our contingent obligations in the table above, we do not expect to fund the full amounts under the letters of credit and guarantees. Lease payments under the High Desert operating lease are reflected in the table above. The lease balance at the end of the lease term is currently estimated to be $600 million. This amount is included as a guarantee in the table above. The table above does not include the fixed payment portions of our mark-to-market energy assets and liabilities. We discuss the expected settlement terms of these contracts in the Mark-to-Market Energy Revenues section on page 28. 40 Liquidity Provisions - -------------------- We have certain agreements that contain provisions that would require additional collateral upon significant decreases in the Senior Unsecured Debt credit ratings of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities. However, if Constellation Energy's credit ratings were to fall three or more rating levels from our present rating to a level below investment grade, under counterparty contracts related to our origination and risk management operation, where we are obligated to post collateral, we would have collateral obligations of $370 million. Based on market conditions and contractual obligations at the time of such a downgrade, we could be required to post collateral in an amount which could exceed the current obligations and which could be material. In many cases customers of our origination and risk management operation rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business prospects of that operation. The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not directly affected by decreases in credit ratings. If these clauses are violated, the lending institutions can decline making new advances or issuing new letters of credit, but cannot accelerate existing amounts outstanding. The credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 0.65. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants. Constellation Energy also provides credit support to Calvert Cliffs and Nine Mile Point to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants. - -------------------------------------------------------------------------------- Other Matters - ------------- Environmental Matters - --------------------- We are subject to federal, state, and local laws and regulations that work to improve or maintain the quality of the environment. If certain substances were disposed of, or released at any of our properties, whether currently operating or not, these laws and regulations require us to remove or remedy the effect on the environment. This includes Environmental Protection Agency Superfund sites. You will find details of our environmental matters in the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 13 and in our 2001 Annual Report on Form 10-K in Item 1. Business - Environmental Matters. These details include financial information. Some of the information is about costs that may be material. Accounting Standards Issued - --------------------------- We discuss recently issued accounting standards in the Accounting Standards Issued section of the Notes to Consolidated Financial Statements beginning on page 18. - -------------------------------------------------------------------------------- Item 3. Quantitative and Qualitative Disclosures About Market Risk - ------------------------------------------------------------------ We discuss the following information related to our market risk: o financing activities and risk management and hedging activities sections in the Notes to Consolidated Financial Statements beginning on page 13, and o activities of our origination and risk management operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 27. 41 PART II. - -------- OTHER INFORMATION - ----------------- Item 1. Legal Proceedings - ------- ----------------- 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. In 2002, the court issued an order to the plaintiff asking that he show cause why he had not yet served the defendants. In April 2002, a second show cause order was issued. The plaintiff has until June 15, 2002 to respond. 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 555 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, 37 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, the 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. 42 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. On April 1, 2002, the Maryland Court of Special Appeals ruled against MAPSA on each of its arguments. MAPSA may file an appeal to this decision with the Maryland Court of Appeals. 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. 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. On April 1, 2002, the Maryland Court of Special Appeals ruled against MAPSA on each of its arguments. MAPSA may file an appeal to this decision with the Maryland Court of Appeals. 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. - -------------------------------------------------------------------------------- Item 5. Other Information - ------- ----------------- 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's 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, o 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, 43 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 the other sections of this report and 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 neither Constellation Energy nor BGE assume responsibility to update these forward looking statements. - -------------------------------------------------------------------------------- Item 6. Exhibits and Reports on Form 8-K - ---------------------------------------- (a) Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges. Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. (b) Reports on Form 8-K for the quarter ended March 31, 2002: Date Filed Items Reported ---------- -------------- January 30, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits January 31, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits March 19, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits 44 SIGNATURE 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 thereunto duly authorized. CONSTELLATION ENERGY GROUP, INC. ----------------------------------------------- (Registrant) BALTIMORE GAS AND ELECTRIC COMPANY ----------------------------------------------- (Registrant) Date: May 15, 2002 /s/ E. Follin Smith - ------------------ ------------------------------------------------ E. Follin Smith, Senior Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 45 EX-99 4 ex12a.txt EXHIBIT 12A Exhibit No. 12a CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended --------------------------------------------------------------------------------------- March December December December December December 2002 2001 2000 1999 1998 1997 ----------- ------------ ------------ ------------ ------------ ------------ (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effect of Change in Accounting Principle) $ 207.7 $ 82.4 $ 345.3 $ 326.4 $ 305.9 $ 254.1 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 100.4 29.7 221.4 182.5 169.3 145.1 ----------- ------------ ------------ ------------ ------------ ------------ Adjusted Income $ 308.1 $ 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 $ 218.9 $ 226.1 $ 261.5 $ 245.7 $ 255.3 $ 234.2 Earnings Required for BGE Preference Stock Dividends 21.3 21.4 21.9 21.0 33.8 45.1 Capitalized Interest 54.0 55.8 21.1 2.7 3.6 8.4 Interest Factor in Rentals 2.1 2.0 2.2 1.8 1.9 1.9 ----------- ------------ ------------ ------------ ------------ ------------ Total Fixed Charges $ 296.3 $ 305.3 $ 306.7 $ 271.2 $ 294.6 $ 289.6 ----------- ------------ ------------ ------------ ------------ ------------ Earnings (1) $ 550.4 $ 361.6 $ 852.3 $ 777.4 $ 766.2 $ 680.4 =========== ============ ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 1.86 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-99 5 ex12b.txt EXHIBIT 12B Exhibit No. 12b BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended --------------------------------------------------------------------------------------- March December December December December December 2002 2001 2000 1999 1998 1997 ------------- ------------- ------------ ------------ ------------ ------------ (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss) $ 86.1 $ 97.3 $ 143.5 $ 328.4 $ 327.7 $ 282.8 Taxes on Income 52.7 60.3 94.2 182.0 181.3 161.5 ------------- ------------- ------------ ------------ ------------ ------------ Adjusted Income $ 138.8 $ 157.6 $ 237.7 $ 510.4 $ 509.0 $ 444.3 ------------- ------------- ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 150.8 $ 158.8 $ 186.8 $ 206.4 $ 255.3 $ 234.2 Capitalized Interest - - - 0.4 3.6 8.4 Interest Factor in Rentals 0.7 0.7 0.9 1.0 1.9 1.9 ------------- ------------- ------------ ------------ ------------ ------------ Total Fixed Charges $ 151.5 $ 159.5 $ 187.7 $ 207.8 $ 260.8 $ 244.5 ------------- ------------- ------------ ------------ ------------ ------------ Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 13.2 $ 13.2 $ 13.2 $ 13.5 $ 21.8 $ 28.7 Income Tax Required 8.1 8.2 8.7 7.5 12.0 16.4 ------------- ------------- ------------ ------------ ------------ ------------ Total Preferred and Preference Dividend Requirements $ 21.3 $ 21.4 $ 21.9 $ 21.0 $ 33.8 $ 45.1 ------------- ------------- ------------ ------------ ------------ ------------ Total Fixed Charges and Preferred and Preference Dividend Requirements $ 172.8 $ 180.9 $ 209.6 $ 228.8 $ 294.6 $ 289.6 ============= ============= ============ ============ ============ ============ Earnings (2) $ 290.3 $ 317.1 $ 425.4 $ 717.8 $ 766.2 $ 680.4 ============= ============= ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 1.92 1.99 2.27 3.45 2.94 2.78 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 1.68 1.75 2.03 3.14 2.60 2.35
(1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. -----END PRIVACY-ENHANCED MESSAGE-----