10-Q 1 f10q2q02.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 JUNE 30, 2002 Commission File Exact name of registrant IRS Employer 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) 750 E. PRATT STREET, BALTIMORE, MARYLAND 21202 ----------------------------------------------- ------- (Address of principal executive offices) (Zip Code) 410-234-5000 ------------ (Registrants' telephone number, including area code) 250 W. PRATT STREET, BALTIMORE, MARYLAND 21201 ----------------------------------------------- ------- (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 164,362,487 shares outstanding of Constellation Energy Group, Inc. on July 31, 2002. Baltimore Gas and Electric Company meets the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and is therefore filing this form in the reduced disclosure format. 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........................................................................... 21 Application of Critical Accounting Policies............................................ 22 Events of 2002......................................................................... 23 Strategy............................................................................... 26 Business Environment................................................................... 27 Results of Operations.................................................................. 31 Financial Condition.................................................................... 45 Capital Resources...................................................................... 46 Other Matters.......................................................................... 48 Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 48 Part II -- Other Information Item 1 -- Legal Proceedings...................................................................... 49 Item 4 -- Submission of Matters to a Vote of Security Holders.................................... 50 Item 5 -- Other Information...................................................................... 51 Item 6 -- Exhibits and Reports on Form 8-K....................................................... 51 Signature........................................................................................ 52
2 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 --------------------------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Nonregulated revenues $ 449.8 $219.1 $ 808.7 $ 505.2 Regulated electric revenues 480.4 497.4 940.7 989.6 Regulated gas revenues 90.6 109.6 311.4 461.8 --------------------------------------------------------------------------------------------------------------------------- Total revenues 1,020.8 826.1 2,060.8 1,956.6 Expenses Operating expenses 639.0 514.7 1,308.9 1,264.8 Workforce reduction costs 13.3 -- 39.2 -- Loss on sale of turbine 6.0 -- 6.0 -- Depreciation and amortization 117.2 102.0 234.3 205.6 Taxes other than income taxes 63.6 55.5 129.2 113.9 --------------------------------------------------------------------------------------------------------------------------- Total expenses 839.1 672.2 1,717.6 1,584.3 Gains on Sale of Investments and Other Assets 3.2 17.1 260.3 33.7 --------------------------------------------------------------------------------------------------------------------------- Income from Operations 184.9 171.0 603.5 406.0 Other Income 5.1 4.2 8.9 3.0 --------------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 190.0 175.2 612.4 409.0 Fixed Charges Interest expense 79.5 72.5 146.6 150.5 Interest capitalized and allowance for borrowed funds used during construction (20.1) (18.8) (31.9) (34.1) BGE preference stock dividends 3.3 3.3 6.6 6.6 --------------------------------------------------------------------------------------------------------------------------- Total fixed charges 62.7 57.0 121.3 123.0 --------------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 127.3 118.2 491.1 286.0 Income Taxes Current 6.7 36.5 167.7 112.4 Deferred 41.3 8.1 17.4 (1.2) Investment tax credit adjustments (2.0) (2.0) (4.0) (4.1) --------------------------------------------------------------------------------------------------------------------------- Total income taxes 46.0 42.6 181.1 107.1 --------------------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Change in Accounting Principle 81.3 75.6 310.0 178.9 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 -- -- -- 8.5 --------------------------------------------------------------------------------------------------------------------------- Net Income $ 81.3 $ 75.6 $ 310.0 $ 187.4 =========================================================================================================================== Earnings Applicable to Common Stock $ 81.3 $ 75.6 $ 310.0 $ 187.4 =========================================================================================================================== Average Shares of Common Stock Outstanding 164.0 163.7 163.9 157.8 Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution Before Cumulative Effect of Change in Accounting Principle $ 0.50 $ 0.46 $ 1.89 $ 1.13 Cumulative Effect of Change in Accounting Principle -- -- -- .06 --------------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution $ 0.50 $ 0.46 $ 1.89 $ 1.19 Dividends Declared Per Common Share $ 0.24 $ 0.12 $ 0.48 $ 0.24 Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 --------------------------------------------------------------------------------------------------------------------------- (In millions) Net Income $ 81.3 $ 75.6 $310.0 $187.4 Reclassification adjustment - gains on sale of investments included in net income, net of taxes -- (0.1) (154.9) (9.6) Other comprehensive income (loss), net of taxes 30.6 193.7 (17.1) 188.9 --------------------------------------------------------------------------------------------------------------------------- Comprehensive Income Before Cumulative Effect of Change in Accounting Principle 111.9 269.2 138.0 366.7 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6 -- -- -- (35.5) --------------------------------------------------------------------------------------------------------------------------- Comprehensive Income $111.9 $269.2 $138.0 $331.2 ===========================================================================================================================
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
June 30, December 31, 2002* 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 251.0 $ 72.4 Accounts receivable (net of allowance for uncollectibles of $24.9 and $22.8, respectively) 757.9 738.9 Trading securities 88.2 178.2 Mark-to-market energy assets 403.0 398.4 Fuel stocks 118.2 108.0 Materials and supplies 213.4 205.3 Prepaid taxes other than income taxes 9.1 93.4 Other 36.6 65.6 ------------------------------------------------------------------------------------------------------------------- Total current assets 1,877.4 1,860.2 ------------------------------------------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 96.9 210.7 Investments in power projects 455.9 499.1 Investment in Orion Power Holdings, Inc. -- 442.5 Financial investments 38.3 60.7 Nuclear decommissioning trust funds 676.4 683.5 Mark-to-market energy assets 1,184.4 1,819.8 Other 275.0 207.4 ------------------------------------------------------------------------------------------------------------------- Total investments and other assets 2,726.9 3,923.7 ------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment Regulated property, plant and equipment 5,005.1 4,948.7 Nonregulated generation property, plant and equipment 6,676.8 6,551.1 Other nonregulated property, plant and equipment 201.7 192.9 Nuclear fuel (net of amortization) 201.4 169.5 Accumulated depreciation (4,234.9) (4,161.8) ------------------------------------------------------------------------------------------------------------------- Net property, plant and equipment 7,850.1 7,700.4 ------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 428.2 463.8 Other 130.4 129.5 ------------------------------------------------------------------------------------------------------------------- Total deferred charges 558.6 593.3 ------------------------------------------------------------------------------------------------------------------- Total Assets $13,013.0 $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
June 30, December 31, 2002* 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 15.5 $ 975.0 Current portion of long-term debt 637.5 1,406.7 Accounts payable 616.4 523.3 Mark-to-market energy liabilities 275.9 323.3 Dividends declared 42.7 23.0 Other 303.5 308.2 ------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,891.5 3,559.5 ------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,335.2 1,431.0 Mark-to-market energy liabilities 802.5 1,476.5 Net pension liability 126.3 173.3 Postretirement and postemployment benefits 347.2 330.9 Deferred investment tax credits 89.6 93.4 Other 249.9 266.9 ------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 2,950.7 3,772.0 ------------------------------------------------------------------------------------------------------------------- Long-term Debt Long-term debt of Constellation Energy 2,100.0 935.0 Long-term debt of nonregulated businesses 403.1 769.1 First refunding mortgage bonds of BGE 1,040.7 1,040.7 Other long-term debt of BGE 918.1 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 (12.8) (5.2) Current portion of long-term debt (637.5) (1,406.7) ------------------------------------------------------------------------------------------------------------------- Total long-term debt 4,061.6 2,712.5 ------------------------------------------------------------------------------------------------------------------- BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholders' Equity Common stock 2,060.1 2,042.2 Retained earnings 1,841.2 1,611.5 Accumulated other comprehensive income 17.9 189.9 ------------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 3,919.2 3,843.6 ------------------------------------------------------------------------------------------------------------------- Total capitalization 8,170.8 6,746.1 ------------------------------------------------------------------------------------------------------------------- Total Liabilities and Capitalization $13,013.0 $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)
Six Months Ended June 30, 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $310.0 $187.4 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle -- (8.5) Depreciation and amortization 251.4 227.6 Deferred income taxes 17.4 (1.2) Investment tax credit adjustments (4.0) (4.1) Deferred fuel costs 24.6 42.8 Pension and postemployment benefits (96.0) 14.0 Gains on sale of investments (260.3) (33.7) Loss (Gain) on sale of plant assets 6.0 (9.5) Workforce reduction costs 39.2 -- Equity in earnings of affiliates and joint ventures (net) 43.2 (14.2) Changes in mark-to-market energy assets and liabilities (90.6) (107.8) Changes in other current assets 93.4 94.0 Changes in other current liabilities 102.8 (99.0) Other (103.6) (26.8) ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 333.5 261.0 ------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (426.3) (669.6) Contributions to nuclear decommissioning trust funds (8.8) (13.2) Purchases of marketable equity securities (0.4) (23.7) Sales of marketable equity securities 116.8 70.9 Sale of investment in Orion Power Holdings, Inc. 454.1 26.2 Sale of real estate investments 113.8 -- Sale of property, plant and equipment 38.4 49.5 Other investments 7.9 (8.6) ------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) investing activities 295.5 (568.5) ------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net (maturity) issuance of short-term borrowings (959.5) 66.6 Proceeds from issuance of Long-term debt 1,823.0 844.6 Common stock 10.7 504.4 Repayment of long-term debt (1,255.6) (1,106.6) Common stock dividends paid (59.0) (81.4) Other (10.0) 9.0 ------------------------------------------------------------------------------------------------------------------- Net cash (used in) provided by financing activities (450.4) 236.6 ------------------------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 178.6 (70.9) Cash and Cash Equivalents at Beginning of Period 72.4 182.7 ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $251.0 $111.8 =================================================================================================================== Other Cash Flow Information --------------------------- Cash paid during the period for: Interest (net of amounts capitalized) $ 86.2 $116.9 Income taxes $134.1 $133.5
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 Six Months Ended June 30, June 30, 2002 2001 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Revenues Electric revenues $480.4 $497.5 $ 940.8 $ 989.8 Gas revenues 92.5 109.6 315.9 467.3 ------------------------------------------------------------------------------------------------------------------- Total revenues 572.9 607.1 1,256.7 1,457.1 Expenses Operating expenses: Electric fuel and purchased energy 273.8 293.9 514.3 559.7 Gas purchased for resale 38.7 52.2 163.0 305.1 Operations and maintenance 81.6 87.5 166.2 173.9 Workforce reduction costs 7.9 -- 28.8 -- Depreciation and amortization 55.8 55.5 112.3 113.2 Taxes other than income taxes 42.0 43.3 86.1 89.3 ------------------------------------------------------------------------------------------------------------------- Total expenses 499.8 532.4 1,070.7 1,241.2 ------------------------------------------------------------------------------------------------------------------- Income from Operations 73.1 74.7 186.0 215.9 Other Income (Expense) 0.8 1.5 0.2 (0.8) ------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 73.9 76.2 186.2 215.1 Fixed Charges Interest expense (net) 35.0 39.2 69.5 81.5 Allowance for borrowed funds used during construction (0.4) (1.1) (0.8) (1.4) ------------------------------------------------------------------------------------------------------------------- Total fixed charges 34.6 38.1 68.7 80.1 ------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 39.3 38.1 117.5 135.0 Income Taxes Current 19.1 19.5 66.0 60.3 Deferred (2.9) (4.0) (18.3) (5.7) Investment tax credit adjustments (0.5) (0.6) (1.0) (1.2) ------------------------------------------------------------------------------------------------------------------- Total income taxes 15.7 14.9 46.7 53.4 ------------------------------------------------------------------------------------------------------------------- Net Income 23.6 23.2 70.8 81.6 Preference Stock Dividends 3.3 3.3 6.6 6.6 ------------------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 20.3 $ 19.9 $ 64.2 $ 75.0 ===================================================================================================================
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
June 30, December 31, 2002* 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 19.8 $ 37.4 Accounts receivable (net of allowance for uncollectibles of $14.0 and $13.4 respectively) 327.5 295.2 Investment in cash pool, affiliated company 736.1 439.1 Accounts receivable, affiliated companies 134.0 133.4 Fuel stocks 36.1 52.3 Materials and supplies 34.3 33.1 Prepaid taxes other than income taxes 0.9 72.5 Other 4.6 7.6 ------------------------------------------------------------------------------------------------------------------- Total current assets 1,293.3 1,070.6 ------------------------------------------------------------------------------------------------------------------- Other Assets Receivable, affiliated company 13.3 113.3 Other 80.3 74.5 ------------------------------------------------------------------------------------------------------------------- Total other assets 93.6 187.8 ------------------------------------------------------------------------------------------------------------------- Utility Plant Plant in service Electric 3,389.5 3,349.9 Gas 1,022.8 1,014.4 Common 499.9 498.1 ------------------------------------------------------------------------------------------------------------------- Total plant in service 4,912.2 4,862.4 Accumulated depreciation (1,812.2) (1,751.4) ------------------------------------------------------------------------------------------------------------------- Net plant in service 3,100.0 3,111.0 Construction work in progress 88.4 81.8 Plant held for future use 4.5 4.5 ------------------------------------------------------------------------------------------------------------------- Net utility plant 3,192.9 3,197.3 ------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 428.2 463.8 Other 32.2 35.0 ------------------------------------------------------------------------------------------------------------------- Total deferred charges 460.4 498.8 ------------------------------------------------------------------------------------------------------------------- Total Assets $5,040.2 $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
June 30, December 31, 2002* 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Current portion of long-term debt $ 629.5 $ 666.3 Accounts payable 61.0 63.6 Accounts payable, affiliated companies 136.7 92.6 Customer deposits 52.1 50.0 Accrued taxes 42.1 7.6 Accrued interest 43.0 37.0 Accrued vacation costs 17.9 21.7 Other 17.3 39.2 ------------------------------------------------------------------------------------------------------------------- Total current liabilities 999.6 978.0 ------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 483.4 503.1 Postretirement and postemployment benefits 276.8 266.1 Deferred investment tax credits 21.6 22.7 Decommissioning of federal uranium enrichment facilities 19.3 19.3 Other 20.9 22.2 ------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 822.0 833.4 ------------------------------------------------------------------------------------------------------------------- Long-term Debt First refunding mortgage bonds of BGE 1,040.7 1,040.7 Other long-term debt of BGE 918.1 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 59.0 71.0 Unamortized discount and premium (5.1) (3.3) Current portion of long-term debt (629.5) (666.3) ------------------------------------------------------------------------------------------------------------------- Total long-term debt 1,633.2 1,821.7 ------------------------------------------------------------------------------------------------------------------- Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 911.9 711.9 Retained earnings 483.5 419.5 ------------------------------------------------------------------------------------------------------------------- Total common shareholder's equity 1,395.4 1,131.4 ------------------------------------------------------------------------------------------------------------------- Total capitalization 3,218.6 3,143.1 ------------------------------------------------------------------------------------------------------------------- Total Liabilities and Capitalization $5,040.2 $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)
Six Months Ended June 30, 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 70.8 $ 81.6 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 113.8 114.4 Deferred income taxes (18.3) (5.7) Investment tax credit adjustments (1.0) (1.2) Deferred fuel costs 24.6 42.8 Pension and postemployment benefits (32.5) 5.8 Workforce reduction costs 28.8 -- Allowance for equity funds used during construction (1.4) (1.4) Changes in other current assets 149.4 130.9 Changes in other current liabilities 69.8 26.2 Other 5.5 13.0 ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 409.5 406.4 ------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (excluding AFC) (91.3) (121.3) Investment in cash pool at parent (297.0) (224.6) Other (8.5) (9.8) ------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (396.8) (355.7) ------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net maturity of short-term borrowings -- (32.1) Proceeds from issuance of long-term debt 2.0 206.9 Repayment of long-term debt (225.7) (200.0) Capital contribution from parent 200.0 -- Preference stock dividends paid (6.6) (6.6) ------------------------------------------------------------------------------------------------------------------- Net cash used in financing activities (30.3) (31.8) ------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (17.6) 18.9 Cash and Cash Equivalents at Beginning of Period 37.4 21.3 ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 19.8 $ 40.2 =================================================================================================================== Other Cash Flow Information --------------------------- Cash paid during the period for: Interest (net of amounts capitalized) $ 68.3 $ 78.2 Income taxes $ 10.3 $ 64.5
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 ------------------------------------------ Various factors 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 as discussed in Note 2 of our 2001 Annual Report on Form 10-K. In accordance with Emerging Issues Task Force Issue (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. The number of employees that elected to voluntarily retire under the age 50 to 54 VSERP and how many employees would thereafter be involuntarily severed was unknown until after the election period of the age 50 to 54 VSERP, which ended in February 2002. In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP for a total cost of $52.9 million. We involuntary severed 129 employees that resulted in total costs for involuntary severances of $7.3 million. Accordingly, we reversed $17.8 million of the involuntary severance accrual that was recorded in 2001 to reflect the employees that elected the age 50 to 54 VSERP. The $35.1 million of net workforce reduction costs recorded during the first quarter of 2002 as discussed above, consisted of $25.9 million of additional expense and $9.2 million recognized by BGE as a regulatory asset related to its gas business. In the second quarter of 2002, we recognized an $18.8 million settlement charge for our basic, qualified pension plan under Statement of Financial Accounting Standards (SFAS) No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This charge reflects the recognition of actuarial gains and losses associated with employees who have retired and taken their pension in the form of a lump-sum payment. In accordance with SFAS No. 88, this settlement charge could not be recognized with the other workforce reduction costs in the fourth quarter of 2001. Under SFAS No. 88, the settlement charge could not be recognized until lump-sum pension payments exceeded annual pension plan service and interest cost, which occurred in the second quarter of 2002. Partially offsetting the settlement charge, we reversed approximately $2.5 million of previously accrued workforce reduction costs during the second quarter of 2002. This primarily represented the reversal of education and outplacement assistance benefits we accrued that employees did not utilize to the extent expected. The $16.3 million of net workforce reduction costs recorded in the second quarter of 2002 as discussed above, consisted of $13.3 million of additional expense and $3.0 million recognized by BGE as a regulatory asset related to its gas business. The following table summarizes the status of that portion of total workforce reduction costs related to the involuntary severance liability recorded under EITF 94-3: (In millions) Involuntary severance amounts recorded in 2001 $ 25.1 VSERP elections in first quarter of 2002 52.9 Reduction of involuntary severance accrual for age 50 to 54 VSERP elections (17.8) --------- Amounts recorded in first quarter of 2002 35.1 Settlement charge in second quarter of 2002 18.8 Reduction of involuntary severance accrual in second quarter of 2002 (0.6) --------- Amounts recorded in second quarter of 2002 18.2 Cash severance payments made in 2002 (5.9) Amount reflected in long-term pension and postretirement obligations (71.7) -------- Involuntary severance liability balance at June 30, 2002 $ 0.8 ======== The amount reflected in 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, transmits, distributes, and sells electricity in Maryland, and o Our regulated gas business purchases, transports, and sells natural gas in Maryland. o Our remaining nonregulated businesses: - provide energy products and services, - sell and service electric and gas appliances, and heating and air conditioning systems, engage in home improvements, and sell electricity and natural gas, - provide cooling services, - own financial investments, - develop, own, and manage real estate, - own senior-living facilities, and - own interests in Latin American power generation and distribution projects and investments. These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown in the table on the next page. 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. We have reclassified certain prior-period information for comparative purposes based on our reportable operating segments. 12
Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated --------------------------- -------------- -------------- ------------- -------------- --------------- ------------- (In millions) For the three months ended June 30, ----------------------------------- 2002 Unaffiliated revenues $ 318.0 $480.4 $ 90.6 $131.8 $ -- $1,020.8 Intersegment revenues 263.7 -- 1.9 -- (265.6) -- ---------------------------- ------------- -------------- ------------- -------------- ------------ ---------------- Total revenues 581.7 480.4 92.5 131.8 (265.6) 1,020.8 Net income 56.4 17.4 2.9 4.6 -- 81.3 2001 Unaffiliated revenues $ 102.3 $497.4 $109.6 $116.8 $ -- $ 826.1 Intersegment revenues 281.7 0.1 -- 0.8 (282.6) -- ---------------------------- ------------- -------------- ------------- -------------- ------------ ---------------- Total revenues 384.0 497.5 109.6 117.6 (282.6) 826.1 Net income 52.4 18.0 3.0 2.2 -- 75.6 For the six months ended June 30, --------------------------------- 2002 Unaffiliated revenues $ 556.6 $940.7 $311.4 $252.1 $ -- $2,060.8 Intersegment revenues 491.5 0.1 4.5 -- (496.1) -- ---------------------------- ------------- -------------- ------------- -------------- ------------ ---------------- Total revenues 1,048.1 940.8 315.9 252.1 (496.1) 2,060.8 Net income 83.4 33.8 30.7 162.1 -- 310.0 2001 Unaffiliated revenues $ 197.2 $989.6 $461.8 $308.0 $ -- $1,956.6 Intersegment revenues 532.5 0.2 5.5 1.9 (540.1) -- ---------------------------- ------------- -------------- ------------- -------------- ------------ ---------------- Total revenues 729.7 989.8 467.3 309.9 (540.1) 1,956.6 Cumulative effect of change in accounting principle -- -- -- 8.5 -- 8.5 Net income 94.8 45.7 31.7 15.2 -- 187.4
13 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 2002, Constellation Energy arranged a $640 million 364-day revolving credit facility and a $640 million three-year revolving credit facility replacing a $380 million 364-day revolving credit facility. We use these two facilities to support our issuances of commercial paper and letters of credit primarily for our merchant energy business. In addition, a bridge financing facility of $700 million expired in June 2002. This facility was initially established in June 2001 at $2.5 billion primarily to refinance maturities due or callable specifically in connection with plans to separate our businesses and to support our issuances of commercial paper after separation. Constellation Energy also has an existing $188.5 million revolving credit facility available to support our issuances of commercial paper and letters of credit. This facility expires in June 2003. These revolving credit facilities support the issuances of letters of credit up to approximately $1.1 billion. At June 30, 2002, letters of credit that totaled $257.4 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. BGE maintains $150.0 million in annual committed bank lines of credit and a $50 million bank revolving credit agreement to support its commercial paper program. The $50 million 364-day agreement expires in late 2002. As of June 30, 2002, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities. In July 2002, BGE announced a partial call of $11.7 million principal amount of its 7 1/2% Series, due April 15, 2023 First Refunding Mortgage Bonds in connection with its annual sinking fund. Bonds called will be redeemed in whole or in part on August 28, 2002 at the price of 100% of principal, plus accrued interest from April 15, 2002 to August 28, 2002. 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 Financial Condition section of Management's Discussion and Analysis on page 45 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 and electric purchase commitments related to sales programs. The gas commitments expire in 2003 and the electric commitments expire in 2004. At June 30, 2002, the total amount of commitments was $905.6 million and they are primarily related to our merchant energy business. 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 14 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. 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 (a precursor of ozone) 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. 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 our 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 May 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 June 30, 2002, we have spent approximately $12 million. The EPA established new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment that were upheld after various court appeals. 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. 15 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 and again in 2002, using its broad investigatory powers, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA and are waiting to see if the EPA takes any further action. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and/or planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities. The Clean Air Act requires the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA has decided to control mercury emissions from coal-fired plants. Compliance could be required by approximately 2007. Final regulations are expected to be issued in 2004 and would affect all coal-fired boilers. The cost of compliance could be material. Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has since been rejected by the President who instead has asked for an 18% decrease in carbon intensity on a voluntary basis. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol and the President's initiatives on us are unknown as of the date of this report. 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. Clean Water Act --------------- In April 2002, the EPA proposed rules under the Clean Water Act that requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. These rules pertain to existing utilities and non-utility power producers that currently employ a cooling water intake structure and whose flow exceeds 50 million gallons per day. A final action on the proposed rules is expected by August 2003. The proposed rule may require the installation of additional intake screens or other protective measures, as well as extensive site specific study and monitoring requirements. There is also the possibility that the proposed rules may lead to the installation of cooling towers on some facilities. Our compliance costs associated with the final rules 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. However, based on a Record of Decision issued by the EPA, we can 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. 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. The Spring Gardens site was once used to manufacture gas from coal and oil. BGE submitted the required remedial action plans and they were approved by the MDE. Based on the these 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 additional costs could exceed the amount BGE recognized by approximately $14 million. Through June 30, 2002, BGE has spent approximately $38 million for remediation at this site. BGE also investigated other small sites where gas was manufactured in the past. We do not expect the 16 cleanup costs of the remaining smaller 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. Storage of Spent Nuclear Fuel ----------------------------- As previously discussed in our 2001 Annual Report on Form 10-K, on February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation's defense activities. In July 2002, the President signed a resolution approving the Yucca Mountain site after receiving the approval of this site from the U.S. Senate and House of Representatives. This action allows the Department of Energy to apply to the Nuclear Regulatory Commission (NRC) to license the project. The facility is expected to open in 2010. However, the opening of Yucca Mountain could be delayed due to litigation related to the site as a permanent repository for spent nuclear fuel. Insurance --------- 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, an industry-wide retrospective assessment program applies above the industry limit. 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. Nuclear 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. A renewal bill was passed by the U.S. House of Representatives that proposes a change in the annual retrospective premium limit from $10 million to $15 million per reactor per incident and a change in the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident. If approved, these changes would increase the amount we could be assessed to $394.8 million per incident, payable at no more than $60 million per incident per year. The Price-Anderson Act will remain in effect in its current form until it is renewed. We do not know what impact any other changes to the Act may have on us until a final resolution is reached. 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. 17 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 on the previous page, 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% 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. Nuclear 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 Nuclear 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. Non-Nuclear Property Insurance ------------------------------ On July 1, 2002, we renewed our non-nuclear property insurance. Since September 11, 2001, conventional property insurers have excluded or restricted coverage for property damage losses arising from acts of terrorism. Our new conventional property insurance provides a $5 million limit for acts of terrorism. In addition, we elected to participate in an industry mutual insurance program that provides property damage coverage for losses resulting from acts of terrorism above the $5 million provided by our conventional property insurer. This program provides limits of $50 million per occurrence and is subject to a term aggregate limit of $100 million that expires May 1, 2003. These limits are shared among all companies participating in the program. The mutual insurer may renew this program depending upon the availability of reinsurance at the program's expiration. If terrorist acts at any of our facilities result in a loss exceeding this coverage, it could have a significant adverse impact on our financial results. California Power Agreements --------------------------- 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 24, those California entities disclaimed any right they may have to a refund. We do not know if we will still be required to pay any refunds to the California entities party to the settlement agreement. 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 $273.8 million for the quarter ended June 30, 2002 compared to $281.2 million for the same period in 2001 and $514.3 million for the six months ended June 30, 2002 compared to $532.5 million for the same period in 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 18 entity. These costs were approximately $5.7 million for the quarter ended June 30, 2002 compared to $6.4 million for the same period in 2001, and $9.4 million for the six months ended June 30, 2002, compared to $10.1 million for the same period in 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 or issues commercial paper to manage consolidated cash requirements. BGE had invested $736.1 million at June 30, 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. SFAS No. 133 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. We discuss our market risk in more detail in our 2001 Annual Report on Form 10-K. Interest Rates -------------- We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities 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 14, 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 the first quarter of 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 Prices ---------------- At June 30, 2002, our merchant energy business had designated certain fixed-price forward sale contracts as cash-flow hedges of forecasted transactions for the years 2002 through 2010 under SFAS No. 133. Under the provisions of SFAS No. 133, we record gains and losses on energy 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 June 30, 2002, our merchant energy business recorded net unrealized pre-tax gains of $49.7 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income." We expect to reclassify $12.4 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at June 30, 2002. However, the actual amount reclassified into earnings could vary from the amounts recorded at June 30, 2002 due to future changes in market prices. We recognized into earnings a pre-tax gain of $0.4 million for the quarter and a pre-tax loss of $1.7 million for the six months ended June 30, 2002 related to the ineffective portion of our hedges. Physical Delivery Business -------------------------- As a result of the changes in our organization and senior management in late 2001, including the cancellation of business separation and the termination of the power business services agreement with Goldman Sachs, we re-evaluated our load-serving activities in Texas and New England. We determined that since we manage these activities as a physical delivery business rather than a trading business, it is appropriate to apply accrual accounting for these activities. 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, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. In Texas, we serve our customers' energy requirements using physically 19 delivering power purchase agreements and our Rio Nogales plant. 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 origination and risk management revenues included in "Nonregulated revenues." New England Load-Serving Business --------------------------------- 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. We manage this business primarily to assure profitable delivery of customers' energy requirements rather than as a traditional trading activity. Because EITF 98-10 significantly limits the circumstances under which contracts previously designated as a trading activity may be re-designated as non-trading, we presently must continue to include contracts entered into prior to the second quarter of 2002 in our trading activities portfolio that is subject to mark-to-market accounting under EITF 98-10. However, we use accrual accounting for New England load-serving transactions and associated power purchase agreements entered into beginning in the second quarter of 2002. 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 July 2002, the FASB issued SFAS No. 146, Accounting for Exit or Disposal Activities. SFAS No. 146 addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for under EITF 94-3. The provisions of the Statement will be effective for disposal activities initiated after December 31, 2002, with early application encouraged. Currently, we are evaluating this statement and its implications on any future exit or disposal initiative. 20 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 27. 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 44, 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 and six months ended June 30, 2002 and 2001. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income. 21 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 materially 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 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 origination and risk management operation, Constellation Power Source, engages in power marketing activities that include 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 Emerging Issues Task Force Issue (EITF) 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. We record all other revenues in the period earned on an accrual basis for services rendered, commodities or products delivered, or contracts settled. We also designate certain fixed-price forward sales contracts as cash-flow hedges of forecasted transactions under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as discussed in more detail in the Notes to Consolidated Financial Statements - SFAS No. 133 - Hedging Activities section on page 19. 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. Origination and risk management 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 and quantities used to determine fair value reflect management's best estimate considering various factors. However, it is possible that future market prices and actual contract quantities 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 our Consolidated Balance Sheets in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts. The EITF is re-examining the accounting for energy trading contracts. In June 2002, the EITF reached a consensus requiring gains and losses on energy trading contracts (whether realized or unrealized) to be reported as revenue on a net basis in the income statement. This consensus is applicable for periods ending after July 15, 2002 and requires restatement of prior periods. This consensus will not have an impact on our financial statements because we record gains and losses on energy trading contracts on a net revenue basis as previously discussed. 22 During the remainder of 2002, the EITF is scheduled to consider other energy trading accounting issues, including: o the types of contracts included in the scope of energy trading activities and subject to mark-to-market accounting, o techniques for determining the fair value of energy trading contracts for which fair value is based upon models, and o whether gains should be recorded in the income statement at the inception of contracts for which fair value is based upon models. As a result of this review, the EITF may change what types of energy contracts are considered to be trading or the techniques for determining the fair value of energy trading contracts, including limiting or prohibiting the recognition of gains at the inception of contracts. We cannot predict whether or how the EITF may change the accounting for energy trading contracts, but any changes it may require could have a significant impact on our financial results. The EITF is scheduled to complete its consideration of these issues prior to the end of 2002 so that any consensus it reaches can be applied in calendar year 2002 financial statements. We discuss the impact of mark-to-market accounting on our financial results in the Results of Operations -- Merchant Energy Business section on page 32. 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 under two cases. The first is if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset. The second is if we change our intent about an asset from an intent to hold to an intent to sell and the market value is less than the investment in 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. 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 in the fourth quarter of 2001. In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP for a total cost of $52.9 million. We involuntary severed 129 employees that resulted in a total cost for the involuntary severance program of $7.3 million. Accordingly, we reversed $17.8 million of the involuntary severance accrual that was recorded in 2001 to reflect the employees that elected the age 50 to 54 VSERP. The $35.1 million of net workforce reduction costs recorded in the first quarter of 2002 as discussed above, consisted of $25.9 million of additional expense and $9.2 million recognized by BGE as a regulatory asset related to its gas business. In the second quarter of 2002, we recognized an $18.8 million settlement charge for our basic, qualified pension plan under SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This charge reflects the recognition of actuarial gains and losses associated with employees who have retired and taken their pension in the form of a lump-sum payment. In accordance with SFAS No. 88, this settlement charge could not be recognized with 23 the other workforce reduction costs in the fourth quarter of 2001. Under SFAS No. 88, the settlement charge could not be recognized until lump-sum pension payments exceeded annual pension plan service and interest cost, which occurred in the second quarter of 2002. We expect to recognize approximately $5 million of addition settlement charges over the remainder of 2002 as more lump-sum pension payments occur. Partially offsetting the settlement charge, we reversed approximately $2.5 million of previously accrued workforce reduction costs during the second quarter of 2002. This primarily represented the reversal of education and outplacement assistance benefits we accrued that employees did not utilize to the extent expected. The $16.3 million of net workforce reduction costs recorded in the second quarter of 2002 as discussed above, consisted of $13.3 million of additional expense and $3.0 million recognized by BGE as a regulatory asset related to its gas business. Once our workforce reduction efforts to date have been fully implemented, we expect ongoing, full year cost savings of approximately $72 million. These savings will be realized in either labor included in operating expenses or capitalized labor, partially offset by other increases in operating or capital costs. We will continue to examine other cost-cutting measures to remain competitive in our business environment. Pension Plan Assets ------------------- As a result of declines in the financial markets, our actual return on pension plan assets was a loss of approximately 5% through June 30, 2002. If our return on pension plan assets remains unchanged through the end of 2002, we expect to record an after-tax charge to equity of approximately $80 million at December 31, 2002 as a result of increasing our additional minimum pension liability. This amount will be determined by the actual return on pension plan assets for 2002, which depends on the performance of the financial markets, and our discount rate assumption, which depends on year-end interest rates. As a result, the charge to equity could change materially. 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 14. The proceeds were used to repay short-term borrowings and prepay the sellers' financed note of $388.1 million related to our purchase of Nine Mile Point Nuclear Station (Nine Mile Point) in April of 2002. Renegotiations of our High Desert Power Contracts ------------------------------------------------- We are currently leasing and supervising the construction of the High Desert Power Project. The project is scheduled for completion in 2003. 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 the State of 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 the FERC alleging that the participants (including Constellation Power Source) who participated in the California Independent System Operator and California Power Exchange were in violation of their market-based rates authority 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 a "tolling" structure, which provides CDWR the right, but not the obligation, to purchase power at a price linked to the variable cost of production, 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 for 7 years and nine months from the commercial operation date of the plant, the High Desert Power Project will provide energy exclusively to the CDWR. 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. In July 2002, the FASB issued an exposure draft for a new accounting interpretation that if adopted as drafted potentially would impact the accounting for, but not the cash flows associated with, our High Desert operating lease and the related SPE. Under the interpretation, we may be required to consolidate the SPE in our Consolidated Balance Sheets. We would have recorded approximately $377.2 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 June 30, 2002. We discuss our High Desert project in more detail in the Capital Resources section on page 46. 24 Acquisition of NewEnergy ------------------------ In June 2002, we announced the execution of an agreement to purchase AES NewEnergy, Inc. (NewEnergy), a subsidiary of AES Corporation. NewEnergy is a leading national provider of electricity, natural gas, and energy services, serving 4,000 megawatts (MW) of load associated with large commercial and industrial customers in competitive energy markets including the Northeast, Mid-Atlantic, Midwest, Texas and California. Under the terms of the agreement, we will acquire 100% ownership of NewEnergy for $240 million. The purchase price will be adjusted for any change in NewEnergy's working capital as specified in the purchase agreement and its actual working capital at the time of closing. NewEnergy's working capital as provided in the purchase agreement included $64 million of cash and marketable securities. The transaction is expected to close before year-end. The FERC approved the purchase and the waiting period ended under the Hart-Scott-Rodino Antitrust Improvement Act. The purchase remains subject to customary closing conditions. Generating Facilities Commence Operations ----------------------------------------- The following generating facilities commenced operations beginning in the second quarter of 2002. Our origination and risk management operation manages the output of these plants. Capacity Primary Plant Location (MW) Type Fuel -------------- ------------- --------- ------------ ------- Combined Rio Nogales Seguin, TX 800 Cycle Gas Combustion Oleander Brevard Co., FL 510* Turbine Gas *As of the date of this report, one of the four units has not been placed in service. We expect the final unit to be placed in service in the third quarter of 2002. The total capacity of the Oleander plant will be 680 megawatts. As discussed in our Re-designation of Texas Business section on page 38, the output from the Rio Nogales project, along with power purchase agreements, is used to meet our customers' energy requirements in Texas. The Oleander project sells 75% of its output to Seminole Electric Cooperative of Tampa, Florida for seven years. Power sales for 50% of the power begin in December 2002, while power sales for the other 25% begin in May 2003. Additionally, Oleander has signed two power purchase agreements with Florida Power and Light Company that began in June 2002. The first contract to purchase 25% of the plant output runs through April 2003, after which the Seminole contract for the same output begins in 2003. The second contract for the remaining 25% of the output runs through May 2005 and can be extended by either Florida Power and Light Company or Oleander for two years at predetermined prices. We have two remaining generating facilities under construction. We expect our Holland Energy plant in Shelby Co., IL, a 665 MW gas combined cycle facility, to be operational by the fall of 2002. We expect our High Desert plant in Victorville, CA, a 750 MW gas combined cycle facility, to be operational in 2003. Loss on Sale of Steam Turbine ----------------------------- In the fourth quarter of 2001, we recognized a $30 million impairment loss on four turbines, associated with a discontinued development program as required by SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of. Since that time, many other companies have canceled development projects and the market values for turbines have declined significantly. Orders for three of the four turbines were canceled with termination fees paid to the manufacturer consistent with the amount recognized in December 2001. The fourth turbine-generator set was sold during the second quarter of 2002 for a value $6.0 million below its book value. 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 $2.1 million for consulting services provided to Constellation Energy and its subsidiary, Constellation Nuclear during the six months ended June 30, 2002. George P. Stamas served as Secretary of the Company from May 1, 2002 until August 12, 2002. Mr. Stamas is a senior partner at Kirkland and Ellis, who continued to provide legal services to the Company during that period. 25 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 services approximately 14,000 megawatts of peak load. Our merchant energy business owns approximately 10,500 megawatts of generation capacity. We also have approximately 1,400 megawatts of natural gas-fired combined cycle production facilities under construction in California 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 desirable 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, Florida, California, and Texas. In addition, our merchant energy business is focusing on providing energy supply and services to large commercial and industrial customers in these deregulated regions. The growth of BGE and our other 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. 26 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 51. In this section, we discuss in more detail several issues that affect our businesses. General Industry ---------------- The utility industry and energy markets continue to experience significant changes as a result of weaker and more volatile wholesale markets, liquidity issues of various industry participants, lower short-term and long-term power prices, and the slowing of the U.S. economy. Due to market conditions in 2001, we canceled our separation plans and terminated our power business services agreement with Goldman Sachs & Co. (Goldman Sachs) on October 26, 2001 and decided to maintain our existing corporate structure. We also terminated all planned development projects not currently under construction. Separately, we initiated efforts to reduce costs in order to become more competitive and to sell certain non-core assets to focus management's attention and our capital resources on our core energy businesses. During the second quarter of 2002, the energy markets were affected by significant events, including expanded investigations by state and federal authorities into business practices of energy companies in the deregulated power and gas markets relating to "wash trading" to inflate revenues and volumes, and other potential trading practices designed to manipulate market prices. In addition, several merchant energy businesses significantly reduced their energy trading activities due to deteriorating credit quality. During the second quarter, several regional energy markets experienced a significant decline in liquidity. As a result of the reduced market liquidity, Constellation Power Source held energy positions in certain markets longer than it otherwise would have. This caused Constellation Power Source's average value-at-risk for the second quarter to increase to $26 million compared to $19 million in the first quarter of 2002. We discuss the value-at-risk calculation in more detail in the Market Risk section of our 2001 Annual Report on Form 10-K. In response to this reduced market liquidity, Constellation Power Source reduced these positions during the end of the second quarter and the beginning of the third quarter of 2002 and continues to modify its liquidity limits to reflect the underlying liquidity of the various regional energy markets. As a result of these actions, Constellation Power Source's value-at-risk was approximately $5 million as of August 12, 2002. As discussed above, certain companies in the energy industry have been experiencing deteriorating credit quality. We continue to actively manage our credit portfolio to attempt to reduce the impact of a potential counterparty default. As of June 30, 2002, approximately 72% of our credit portfolio was rated at least investment grade by the major rating agencies, with 1% rated below investment grade and 27% not rated. Of the 27% not rated, 91% primarily represents governmental entities, municipalities, cooperatives, or other load serving entities that Constellation Power Source assesses are equivalent to investment grade based on internal credit ratings. We continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our strategies in the Strategy section on page 26. We discuss our liquidity in the Financial Condition section on page 45. Electric Competition -------------------- We are facing competition in the sale of electricity in wholesale power markets and to retail customers. Maryland -------- As a result of the deregulation of electric generation in Maryland, the following occurred effective July 1, 2000: o All customers can choose their electric energy supplier. BGE provides standard offer service for customers that do not select an alternative supplier at fixed rates over various time periods during the transition period. 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 Commercial and industrial customers have up to four service options that will fix electric energy rates and transition charges for a period that ends in 2004 to 2006. o BGE 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. 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 27 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 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 as discussed in the FERC Regulation--Regional Transmission Organizations section on page 29 and its proposal released in July 2002 on a standard market design could provide our merchant energy business other opportunities. We discuss our California Power Purchase Agreements with Pacific Gas & Electric (PGE) and Southern California Edison (SCE) in more detail in our Merchant Energy Business section on page 34. 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. 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 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 24, the California entities disclaimed any right they may have to a refund. We do not know if we will still be required to pay any refunds to the California entities party to the settlement agreement. 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 that BGE can charge customers for electric distribution and gas businesses. The Maryland PSC incorporates into BGE's rates the transmission rates determined by FERC. 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. 28 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 and a current proceeding with the Maryland PSC in more detail in the Gas Cost Adjustments section on page 42. 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 PJM West region recently was formed and Virginia Electric and Power Company is discussing with PJM the formation of a PJM South region. 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, on July 1, 2002, PJM filed for an extension relating to the implementation of a uniform transmission rate until at least January 1, 2005. BGE filed in support of the PJM extension. A uniform rate could expose BGE to higher transmission rates. BGE, jointly with other PJM transmission owners, requested a 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. Cash Management --------------- In August 2002, the FERC issued proposed rules for the regulation of cash management practices of a regulated subsidiary of a nonregulated parent. As currently proposed, we do not believe the proposed rule will have a material effect on our, and BGE's, financial results. Please refer to the Notes to Consolidated Financial Statements section on page 19 for a discussion of our cash management arrangement. 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. 29 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 42. 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 and cooling degree days in the quarters and six months ended June 30, 2002 and 2001, and the percentage change in the number of degree days between these periods in the following table: Quarter Ended Six Months Ended June 30 June 30 2002 2001 2002 2001 --------------------------------------------------------- Heating degree days 493 471 2,616 2,918 Percent change from prior period 4.7% (10.3)% Cooling degree days 295 262 298 262 Percent change from prior period 12.6% 13.7% Other Factors ------------- A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our merchant energy business. These factors include: o seasonal daily and hourly changes in demand, o extreme peak demands, o available supply resources, o transportation availability and reliability within and between regions, o procedures used to maintain the integrity of the physical electricity system during extreme conditions, and o changes in the nature and extent of federal and state regulations. These other factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in: o weather conditions, o market liquidity, o capability and reliability of the physical electricity and gas systems, and o the nature and extent of electricity deregulation. Other factors, aside from weather, also 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 only customers 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. 30 Results of Operations for the Quarter and Six Months Ended June 30, 2002 ------------------------------------------------------------------------ Compared with the Same Periods 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 44. Overview -------- Net Income ---------- Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ---------------------------------------------------------- (In millions) Net Income Before Special Items Included in Operations: Merchant energy $63.5 $52.4 $ 93.5 $ 94.8 Regulated electric 22.2 18.0 51.2 45.7 Regulated gas 2.9 3.0 30.7 31.7 Other nonregulated 2.7 (8.1) (4.1) (13.7) ---------------------------------------------------------- Net Income Before Special Items Included in Operations 91.3 65.3 171.3 158.5 Special Items Included in Operations: Gains on sale of investments and other assets 1.9 10.3 166.2 20.4 Workforce reduction costs (8.0) -- (23.6) -- Loss on sale of turbine (3.9) -- (3.9) -- ---------------------------------------------------------- Net Income Before Cumulative Effect of Change in Accounting Principle 81.3 75.6 310.0 178.9 Cumulative Effect of Change in Accounting Principle -- -- -- 8.5 ---------------------------------------------------------- Net Income $81.3 $75.6 $310.0 $187.4 ========================================================== Quarter Ended June 30, 2002 --------------------------- Our total net income for the quarter ended June 30, 2002 increased $5.7 million, or $.04 per share, compared to the same period of 2001 mostly because of the following: o We had higher earnings from our origination and risk management operation. o We experienced warmer weather in the central Maryland region. o The addition of Nine Mile Point Nuclear Station (Nine Mile Point) to the generation fleet increased income due to the seasonality of the power purchase agreement for this plant. o We had cost reductions due to productivity initiatives associated with our corporate-wide workforce reduction and other productivity programs. o We had higher earnings from our other nonregulated businesses due to the growth of our energy services business and improved results from our international portfolio. These increases were partially offset by the following: o We had lower earnings due to the extended outage at Calvert Cliffs to replace the steam generators at Unit 1. o We recorded costs of $8.0 million after-tax, or $.05 per share, associated with our corporate-wide workforce reduction programs. o Our merchant energy business experienced higher coal costs and lower energy prices in California. o Our merchant energy business recorded a loss on the sale of a turbine of $3.9 million after-tax, or $.02 per share. o Our other nonregulated businesses had lower gains on the sale of securities and other assets in 2002 compared to 2001. Six Months Ended June 30, 2002 ------------------------------ Our total net income for the six months ended June 30, 2002 increased $122.6 million, or $.70 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 23. o We had higher earnings from our origination and risk management operation. o We had cost reductions due to productivity initiatives associated with our corporate-wide workforce reduction and other productivity programs. 31 o We had higher earnings from our other nonregulated businesses due to the growth of our energy services business and improved results from our international portfolio. These increases were partially offset by the following: o We had lower earnings due to the extended outage at Calvert Cliffs to replace the steam generators at Unit 1. o We recorded costs of $23.6 million after-tax, or $.15 per share, associated with our corporate-wide workforce reduction programs. o Our merchant energy business experienced lower energy prices in California. o Our merchant energy business recorded a loss on the sale of a turbine of $3.9 million, or $.02 per share. In addition, our other nonregulated businesses recorded the following in the first six months 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 $20.4 million after-tax, or $.13 per share. Earnings per share contributions from all of our business segments for the six months ended June 30, 2002 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. Merchant Energy Business ------------------------ Our merchant energy business is exposed to various market risks as discussed further in the General Industry section on page 27 and 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 fair value of contracts in our origination and risk management operation that are subject to mark-to-market accounting in revenues on a net basis 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, including the load-serving activities in Texas and New England as discussed further in the Physical Delivery Business section on page 38. o Prior to the settlement of the forecasted transaction being hedged, we record changes in the fair 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 the changes in fair value of hedges in earnings in the period the settlement of the hedged transaction occurs. We record the ineffective portion of the changes in fair value of 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 Origination and Risk Management Revenues section on page 34. 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 22 and in Note 1 of our 2001 Annual Report on Form 10-K. As discussed in the Business Environment -- Electric Competition section on page 27, 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. 32 Net Income Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ---------------------------- ------- ------ --------- ------- (In millions) Revenues $581.7 $384.0 $1,048.1 $729.7 Operating expenses 393.6 261.4 728.3 487.5 Workforce reduction costs 5.3 -- 10.3 -- Loss on sale of turbine 6.0 -- 6.0 -- Depreciation and amortization 57.2 40.7 113.9 81.0 Taxes other than income taxes 20.5 11.3 41.0 22.8 ---------------------------- ------- ------ --------- ------- Income from Operations $ 99.1 $ 70.6 $ 148.6 $138.4 ============================ ======= ====== ========= ======= Net Income $ 56.4 $ 52.4 $ 83.4 $ 94.8 ============================ ======= ====== ========= ======= Net Income Before Special Items Included in Operations $63.5 $52.4 $93.5 $94.8 Workforce reduction costs (3.2) -- (6.2) -- Loss on sale of turbine (3.9) -- (3.9) -- ---------------------------- ------- ------ --------- ------- Net Income $56.4 $52.4 $83.4 $94.8 ============================ ======= ====== ========= ======= 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 13 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Revenues -------- Merchant energy revenues increased $197.7 million during the quarter and $318.4 million during the six months ended June 30, 2002 compared to the same periods of 2001 mostly due to: o higher revenues from other sales of generation from our new facilities placed in service in mid-summer 2001 and during the second quarter of 2002, and Nine Mile Point, o higher revenues from origination and risk management revenues recorded on a mark-to-market basis, and o the re-designation of our Texas load-serving business to non-trading as discussed in more detail on page 38. These increases were partially offset by a decrease in revenues related to supplying BGE's standard offer service requirements and lower revenues from our California power purchase agreements with PGE and SCE. 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 $12.1 million, including CTC revenues that decreased $2.4 million, during the quarter ended June 30, 2002 compared to the same period of 2001. The revenues from BGE's Standard Offer Service requirements decreased by $22.3 million, including CTC revenues that decreased $7.0 million, during the six months ended June 30, 2002 compared to the same period of 2001. These decreases were due to approximately 1,200 megawatts of larger commercial and industrial customers leaving BGE's standard offer service and electing other electric generation suppliers. As a result, our merchant energy business has 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. In addition, the CTC rate our merchant energy business receives from BGE customers declines over the transition period as previously discussed in the Electric Competition - Maryland section on page 27. Other Merchant Generation Revenues ---------------------------------- Excluding revenues from BGE's Standard Offer Service, merchant generation revenues increased $170.4 million during the quarter and $254.5 million during the six months ended June 30, 2002 compared to the same periods of 2001 primarily due to: o revenues of $103.3 million for the quarter and $195.8 million for the six months from Nine Mile Point that was acquired in November 2001, o an increase of $74.8 million for the quarter and $98.2 million for the six months related to the re-designation of the Texas load-serving business to non-trading from mark-to-market energy revenues, and o revenues of $14.1 million for the quarter and $17.5 million for the six months from our new generating facilities that were placed in service during mid-summer 2001 and the second quarter of 2002. These increases were partially offset by $17.2 million during the quarter and $38.6 million during the six months of lower sales of power from our Baltimore plants in excess of that required to serve BGE's standard offer service requirements compared to same periods of 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, our generation operation had lower revenues from our California projects as discussed on the next page, and 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. 33 California Power Purchase Agreements ------------------------------------ Our generation operation has $269.0 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. Under these agreements, the projects supply electricity to these utilities at variable rates. Revenues from these projects, net of credit reserves, decreased $8.4 million during the quarter and $8.0 million for the six months ended June 30, 2002 compared to the same periods of 2001. While California power prices were significantly lower during the first half of 2002 compared to the same period of 2001, first quarter results were 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. As of June 30, 2002, we received $33 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 several months. Accordingly, we reversed all of our credit reserves that totaled $9.1 million during the first quarter of 2002. 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 agreements. Origination and Risk Management Revenues ---------------------------------------- Revenues include net gains and losses from Constellation Power Source origination and risk management activities for which we use the mark-to-market method of accounting. 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 22 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 changes in the level and volatility of forward commodity prices and interest rates, o changes in estimates of customers' load requirements as a result of changes in weather and customer attrition due to the selection of other suppliers, and o the number and size of our open commodity and derivative positions. Origination and risk management revenues were as follows: Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ---------------------------- -------- ------- ------ ------- (In millions) Origination transactions $85.4 $65.6 $ 94.9 $103.5 Risk management activities Realized (13.7) (16.6) 7.2 (47.2) Unrealized 18.6 (2.0) 52.0 2.7 ---------------------------- -------- ------- ------ ------- Total risk management activities 4.9 (18.6) 59.2 (44.5) ---------------------------- -------- ------- ------ ------- Total $90.3 $47.0 $154.1 $ 59.0 ============================ ======== ======= ====== ======= Revenues from 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 origination and risk management 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. The relationship of the realized portion of revenue to total origination and risk management revenue in the table above 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 36. Origination and risk management revenues increased $43.3 million during the quarter ended June 30, 2002 compared to the same period of 2001 because of net gains from risk management activities and increased revenues from origination transactions. The increase in net gains from risk management activities is primarily due to favorable changes in regional power prices, price volatility, and other factors in the second quarter of 2002 compared to 34 the same period of 2001. The increase in origination revenue reflects higher margins on individually significant transactions in 2002 as compared to the same period of 2001. Origination and risk management revenues increased $95.1 million during the six months ended June 30, 2002 compared to the same period of 2001 mostly because of net gains from risk management activities partially offset by lower revenues from origination transactions. The increase in net gains from risk management activities is primarily due to favorable changes in regional power prices, price volatility, and other factors in 2002 compared to the same period of 2001. The decreases in origination revenue reflect 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 (physical) 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, estimated quantities, or both. We discuss our modeling techniques on page 37. Mark-to-market energy assets and liabilities consisted of the following: June 30, December 31, 2002 2001 ---------------------------------------------------------- (In millions) Current Assets $ 403.0 $ 398.4 Noncurrent Assets 1,184.4 1,819.8 ---------------------------------------------------------- Total Assets 1,587.4 2,218.2 ---------------------------------------------------------- Current Liabilities 275.9 323.3 Noncurrent Liabilities 802.5 1,476.5 ---------------------------------------------------------- Total Liabilities 1,078.4 1,799.8 ---------------------------------------------------------- Net mark-to-market energy asset $ 509.0 $ 418.4 ========================================================== The primary components of our net mark-to-market energy asset are the following as of June 30, 2002: (In millions) New England load-serving $253 PJM generation hedge 118 Other positions 138 ------------------------------------------- Total $509 =========================================== The New England load-serving portion of the net asset primarily represents the fair value of contracts to serve customers' full energy requirements and related energy supply resources. The PJM generation hedge is comprised of a group of options that serve as an economic hedge of the PJM generation portfolio. These options give us the right to sell power at a floor price which is valuable to our generation operation when market prices are low and also give us the right to buy power at a capped price, which adds value when market prices are high. A significant portion of the remaining $138 million relates to power sales transactions in California that are fully hedged. The following are the primary sources of the change in the net mark-to-market energy asset during quarter ended June 30, 2002 and the six months ended June 30, 2002: Change in Net Mark-to-Market Energy Asset Quarter Ended Six Months Ended June 30, 2002 June 30, 2002 -------------------------------------------------------------------- (In millions) Fair value beginning of period $365.1 $418.4 Changes in fair value recorded as revenues Origination transactions $85.4 $94.9 ------ ------ Unrealized risk management revenues: Contracts settled 13.7 (7.2) Changes in valuation techniques 3.8 4.3 Unrealized changes in fair value 1.1 54.9 ------ ------ Total unrealized risk management revenues $18.6 $52.0 ------ ------ Total changes in fair value recorded as revenues 104.0 146.9 Changes in fair value recorded as operating expenses 2.7 3.0 Net change in premiums on options 26.5 (10.6) Texas contracts re-designated as non-trading -- (63.3) Other changes in fair value 10.7 14.6 ------------------------------------------------------------------ Fair value at June 30, 2002 $509.0 $509.0 ================================================================== Origination transactions represent the initial unrealized fair value at the time these contracts are executed. Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements 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 other valuation adjustments. 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. 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 35 the volatility of energy prices. During the second quarter of 2002, we purchased options as part of our overall risk management strategy that resulted in a higher net mark-to-market energy asset. However, the net change in premiums on options for the six months ended June 30, 2002 reflects a net increase in options sold that reduced our exposure to option volatility. We discuss our re-designation of the Texas load-serving activities as non-trading in more detail on page 38. The settlement term of the net mark-to-market energy asset and sources of fair value as of June 30, 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 $106.7 $56.4 $(19.6) $(35.7) $13.6 $(2.9) $ 0.9 $ 4.2 $123.6 Prices based on models (32.7) (13.7) 109.7 81.7 64.2 57.0 124.9 (5.7) 385.4 --------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ---------- Total net mark-to-market energy asset $ 74.0 $42.7 $ 90.1 $ 46.0 $77.8 $54.1 $125.8 $(1.5) $509.0 ===================== ========== ======== ========= ========== ========= ========== ========== =========== ==========
The portion of the net mark-to-market energy asset as of June 30, 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 38, 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 and general market conditions 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. We discuss the New England load-serving business in more detail on page 38. 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 $91.1 $56.9 $19.9 $(13.5) $25.8 $(3.2) $ -- $ -- $177.0 Prices based on models 0.3 4.8 (0.7) 11.1 21.1 24.1 18.2 0.1 79.0 --------------------- ---------- -------- --------- --------- -------- ---------- ---------- ----------- ---------- Total $91.4 $61.7 $19.2 $ (2.4) $46.9 $20.9 $18.2 $0.1 $256.0 ===================== ========== ======== ========= ========= ======== ========== ========== =========== ==========
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 36 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 through 2007, depending upon the region, o forward purchases and sales of electricity during off-peak hours for delivery terms through 2007, 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 and oil for delivery terms through 2006, and o options for the purchase and sale of natural gas and oil for delivery terms through 2006. 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 upon underlying contractual terms and incorporate, where appropriate, option pricing models and statistical and simulation procedures. Inputs to the models include: o observable market prices, o estimated market prices in the absence of quoted market prices, o the risk-free market discount rate, o volatility factors, o estimated correlation of energy commodity prices, o estimated volumes for customer requirements, which are influenced by customer switching behavior, impact of temperature on electric prices, and customer acquisition and servicing costs, o estimated volumes for tolling arrangements, and o expected generation profiles of specific regions. Additionally, we incorporate counterparty-specific credit quality and factors for market price and volatility 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 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 June 30, 2002. These amounts do not represent the contractual maturities 37 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. Physical Delivery Business -------------------------- As a result of the changes in our organization and senior management in late 2001, including the cancellation of business separation and the termination of the power business services agreement with Goldman Sachs, we re-evaluated our load-serving activities in Texas and New England. We determined that since we manage these activities as a physical delivery business rather than a trading business, it is appropriate to apply accrual accounting for these activities. 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 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. 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. In Texas, we serve our customers' energy requirements using physically delivering power purchase agreements and our Rio Nogales plant. 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 and $98.2 million for the period February 15, 2002 through June 30, 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." Origination and risk management 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 gain of $10.8 million for the second quarter of 2001 and a net loss of $8.2 million for the six months ended June 30, 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. New England Load-Serving Business --------------------------------- 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. We manage this business primarily to assure profitable delivery of customers' energy requirements rather than as a traditional trading activity. Because EITF 98-10 significantly limits the circumstances under which contracts previously designated as a trading activity may be re-designated as non-trading, we presently must continue to include contracts entered into prior to the second quarter of 2002 in our trading activities portfolio that is subject to mark-to-market accounting under EITF 98-10. However, we use accrual accounting for New England load-serving transactions and associated power purchase agreements entered into beginning in the second quarter of 2002. 38 Operating Expenses ------------------ Merchant energy operating expenses increased $132.2 million during the quarter and $240.8 million for the six months ended June 30, 2002 compared to the same periods of 2001 mostly because of the following: o Operations and maintenance costs increased $51.3 million for the quarter and $109.3 million for the six months. These increases reflect the operations of the new generating facilities and Nine Mile Point. These increases were partially offset by cost reductions due to productivity initiatives associated with our corporate-wide workforce reduction. o Fuel and purchased energy costs increased $13.1 million for the quarter and $14.6 million for the six months. These increases reflect the operations of the new generating 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 higher coal prices. These were partially offset by lower generation at our coal plants. We continue to expect to incur additional costs in the future to operate our coal generating facilities due to higher coal prices. o Increases of $77.3 million for the quarter and $102.0 million for the six months related to the re-designation of the Texas load-serving business to non-trading from energy revenues that are mark-to-market. o Origination and risk management operating expenses increased $7.0 million for the quarter and $36.6 for the six months 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 $5.0 million in the second quarter of 2001 and $11.5 million for the six months 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. Our merchant energy business completed the extended outage at the end of 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 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 23, our merchant energy business recognized expenses of $5.3 million pre-tax, or $3.2 million after-tax, during the quarter and $10.3 million pre-tax, or $6.2 million after-tax, for the six months associated with our workforce reduction efforts. Once our workforce reduction efforts to date have been fully implemented, our merchant energy business expects ongoing, full year cost savings of approximately $24 million. These savings will be realized in either labor included in operating expenses or capitalized labor, partially offset by other increases in operating or capital costs. Loss on Sale of Steam Turbine ----------------------------- As discussed in the Events of 2002 section on page 25, we recognized a $6.0 million pre-tax, or $3.9 million after-tax, impairment loss on the sale of a steam turbine generator set during the second quarter of 2002. Depreciation and Amortization Expense ------------------------------------- Merchant energy depreciation and amortization expense increased $16.5 million during the quarter and $32.9 million for the six months ended June 30, 2002 compared to the same periods of 2001 mostly because of the depreciation and amortization associated with the new generating facilities and Nine Mile Point. Taxes Other than Income Taxes ----------------------------- Merchant energy taxes other than income taxes increased $9.2 million during the quarter and $18.2 million for the six months ended June 30, 2002 as compared to the same periods of 2001 mostly because of taxes other than income taxes associated with Nine Mile Point. 39 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. 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. 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 27. Net Income ---------- Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ------------------------------------------------------------- (In millions) Revenues $480.4 $497.5 $940.8 $989.8 Electric fuel and purchased energy 273.8 293.9 514.3 559.7 Operations and maintenance 59.5 62.9 120.3 124.7 Workforce reduction costs 7.9 -- 28.8 -- Depreciation and amortization 44.0 43.3 87.8 86.7 Taxes other than income taxes 34.2 35.0 68.9 70.9 ------------------------------------------------------------- Income from Operations $ 61.0 $ 62.4 $120.7 $147.8 ============================================================= Net Income $ 17.4 $ 18.0 $ 33.8 $ 45.7 ============================================================= Net Income Before Special Items Included in Operations $22.2 $18.0 $51.2 $45.7 Workforce reduction costs (4.8) -- (17.4) -- ------------------------------------------------------------- Net Income $17.4 $18.0 $33.8 $45.7 ============================================================= 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 13 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 Six Months Ended June 30, June 30, 2002 vs. 2001 2002 vs. 2001 ----------------------------------------------------------- (In millions) Distribution sales volumes $ 2.5 $ (1.8) Standard Offer Service (7.7) (17.2) Fuel rate surcharge (12.5) (27.3) ----------------------------------------------------------- Total change in electric revenues from electric system sales (17.7) (46.3) Other 0.6 (2.7) ----------------------------------------------------------- Total change in electric revenues $(17.1) $(49.0) =========================================================== Distribution Sales Volumes -------------------------- "Distribution sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. The percentage changes in our distribution sales volumes, by type of customer, in 2002 compared to 2001 were: Quarter Ended Six Months Ended June 30, June 30, 2002 vs. 2001 2002 vs. 2001 ------------------------------------------------------- Residential 6.0% (0.8)% Commercial (1.2) (0.5) Industrial (1.0) (1.0) During the quarter ended June 30, 2002, we distributed more electricity to residential customers compared to the same period of 2001 due to warmer weather. We distributed less electricity to commercial and industrial customers due to decreased usage. During the six months ended June 30, 2002 we distributed about the same amount of electricity to all customers. Standard Offer Service ---------------------- As part of the Restructuring Order, BGE provides Standard Offer Service for customers that do not select an alternative generation supplier as previously discussed. Standard Offer Service revenues decreased for the quarter ended June 30, 2002 compared to the same period of 2001 primarily as a result of large commercial and industrial customers leaving BGE's Standard Offer Service and electing other electric generation suppliers. These decreased revenues were partially offset by an increase in the Standard Offer Service rate that BGE charges its customers. Standard Offer Service revenues decreased for the six months ended June 30, 2002 compared to the same period of 2001 primarily as a result of large commercial and industrial customers leaving BGE's Standard Offer Service and electing other electric generation suppliers and lower revenues due to 40 milder winter weather. These decreased revenues were partially offset by an increase in the Standard Offer Service rate that BGE charges its customers. As a result of large commercial and industrial customers leaving BGE's service, BGE also had lower purchased energy expense as discussed in the Electric Fuel and Purchased Energy Expenses section below. 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 below. Electric Fuel and Purchased Energy Expenses ------------------------------------------- Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 -------------------------------------------------------- (In millions) Actual costs $273.8 $281.6 $514.3 $532.9 Net recovery of costs under electric fuel rate clause -- 12.3 -- 26.8 -------------------------------------------------------- Total electric fuel and purchased energy expenses $273.8 $293.9 $514.3 $559.7 ======================================================== Actual Costs ------------ As discussed in the Business Environment--Electric Competition section on page 27, 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 and six months ended June 30, 2002 were lower compared to the same periods of 2001 mostly because BGE purchased less energy due to larger commercial and industrial customers leaving BGE's standard offer service and electing other electric generation suppliers. 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. Electric Operations and Maintenance Expenses -------------------------------------------- Regulated other electric operations and maintenance expenses decreased $3.4 million for the quarter and $4.4 million for the six months ended June 30, 2002 compared to the same periods of 2001 primarily as a result of cost reductions due to productivity initiatives associated with our corporate wide workforce reduction and other productivity initiative programs. Workforce Reduction Costs ------------------------- As previously discussed in the Events of 2002 section on page 23, BGE's electric business recognized expenses of $7.9 million pre-tax, or $4.8 million after-tax, during the quarter and $28.8 million pre-tax, or $17.4 million after-tax, for the six months associated with our workforce reduction efforts. Once our workforce reduction efforts to date have been fully implemented, BGE's electric business expects ongoing, full year cost savings of approximately $33 million. These savings will be realized in either labor included in operating expenses or capitalized labor, partially offset by other increases in operating or capital costs. Other Electric Operating Expenses --------------------------------- Regulated other electric operating expenses were about the same for the quarter and six months ended June 30, 2002 compared to the same periods of 2001. 41 Regulated Gas Business ---------------------- Net Income ---------- Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ------------------------------------------------------------- (In millions) Gas revenues $92.5 $109.6 $315.9 $467.3 Gas purchased for resale 38.7 52.2 163.0 305.1 Operations and maintenance 22.1 24.6 45.9 49.2 Depreciation and amortization 11.8 12.2 24.5 26.5 Taxes other than income taxes 7.8 8.3 17.2 18.4 ------------------------------------------------------------- Income from operations $12.1 $ 12.3 $ 65.3 $ 68.1 ============================================================= Net income $ 2.9 $ 3.0 $ 30.7 $ 31.7 ============================================================= 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 13 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Net income from the regulated gas business was about the same during the quarter ended June 30, 2002 compared to the same period of 2001. Net income from the regulated gas business decreased during the six months ended June 30, 2002 compared to the same period of 2001 mostly due to a decrease in earnings from 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 Six Months Ended June 30, June 30, 2002 vs. 2001 2002 vs. 2001 --------------------------------------------------------- (In millions) Distribution volumes $ (1.7) $ (13.0) Base rates (0.5) (2.3) Weather normalization 1.1 9.9 Gas cost adjustments (11.9) (101.1) --------------------------------------------------------- Total change in gas revenues from gas system sales (13.0) (106.5) Off-system sales (2.7) (42.5) Other (1.4) (2.4) --------------------------------------------------------- Total change in gas revenues $(17.1) $(151.4) ========================================================= Distribution Volumes -------------------- The percentage changes in our gas distribution volumes, by type of customer, in 2002 compared to 2001 were: Quarter Ended Six Months Ended June 30, June 30, 2002 vs. 2001 2002 vs. 2001 ---------------------------------------------------------- Residential (7.4)% (11.8)% Commercial (3.6) 1.2 Industrial (10.0) (5.4) During the quarter ended June 30, 2002, we distributed less gas to residential customers compared to the same period of 2001 mostly due to lower usage per customer partially offset by cooler weather in early spring. We distributed less gas to commercial customers mostly due to lower usage per customer. We distributed 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. During the six months ended June 30, 2002, we distributed 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 distributed more gas to commercial customers mostly due to higher usage per customer and an increased number of customers. We distributed 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 and six months ended June 30, 2002 compared to the same periods 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. The shareholders' portion decreased $0.3 million during the quarter and $2.1 42 million during the six months ended June 30, 2002 compared to the same periods 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 distributed and are included in gas distribution sales volumes. During the quarter and six months ended June 30, 2002, gas cost adjustment revenues decreased compared to the same periods of 2001 mostly because we distributed less gas at a lower price. In our annual gas adjustment clause review proceeding with the Maryland PSC, our gas business is seeking recovery of a previously established regulatory asset of $9.4 million for certain credits that were over-refunded to customers through our market-based rates. Certain parties to the proceeding are petitioning that our gas business should not be allowed to recover these costs. We expect the Maryland PSC to issue an order during the fourth quarter of 2002. Under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, we would be required to write-off the amount, if any, that the Maryland PSC disallowed. As of the date of this report, we cannot determine the outcome of this review by the Maryland PSC. 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 June 30, 2002, revenues from off-system gas sales decreased mostly because the gas we sold was at a lower price partially offset by more gas sold as compared to the same period of 2001. During the six months ended June 30, 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 and six months ended June 30, 2002, gas costs decreased compared to the same periods of 2001 because we bought less gas at a lower price. Other Gas Operating Expenses ---------------------------- During the quarter and six months ended June 30, 2002, other gas operating expenses decreased compared to the same periods of 2001 mostly because of cost reductions associated with our corporate-wide workforce reduction and other productivity initiative programs and lower depreciation and amortization expense. Once our workforce reduction efforts to date have been fully implemented, BGE's gas business expects ongoing, full year cost savings of approximately $15 million. These savings will be realized in either labor included in operating expenses or capitalized labor, partially offset by other increases in operating or capital costs. 43 Other Nonregulated Businesses ----------------------------- Net Income ---------- Quarter Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 --------------------------------------------------------------- (In millions) Revenues $131.8 $117.6 $252.1 $309.9 Operating expenses 116.9 102.3 233.2 279.3 Workforce reduction costs 0.1 -- 0.1 -- Gains on sale of investments and other assets 3.2 17.1 260.3 33.7 Depreciation and amortization 4.2 5.8 8.1 11.4 Taxes other than income taxes 1.1 0.9 2.1 1.8 --------------------------------------------------------------- Income from Operations $ 12.7 $ 25.7 $268.9 $ 51.1 =============================================================== Net Income Before Cumulative Effect of Change in Accounting Principle $4.6 $ 2.2 $162.1 $ 6.7 Cumulative Effect of Change in Accounting Principle -- -- -- 8.5 --------------------------------------------------------------- Net Income $4.6 $ 2.2 $162.1 $15.2 =============================================================== Net Income (Loss) Before Special Items Included in Operations $2.7 $(8.1) $ (4.1) $(13.7) Gains on sale of investments and other assets 1.9 10.3 166.2 20.4 --------------------------------------------------------------- Net Income Before Cumulative Effect of Change in Accounting Principle $4.6 $ 2.2 $162.1 6.7 Cumulative Effect of Change in Accounting Principle -- -- -- 8.5 --------------------------------------------------------------- Net Income $4.6 $ 2.2 $162.1 $ 15.2 =============================================================== 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 13 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. During the quarter ended June 30, 2002, income from operations at our other nonregulated businesses decreased compared to the same period of 2001 mostly because of gains on the sale of securities in the second quarter of 2001 that had a positive impact in that period. During the second quarter of 2001, we recognized a $14.8 million pre-tax gain on the sale of one million shares of our Orion investment. This was partially offset by growth of our energy services business and better performance by our international business in the second quarter of 2002. During the six months ended June 30, 2002, income from operations at our other nonregulated businesses increased compared to the same period of 2001 mostly because of the recognition of a $255.5 million pre-tax gain on the sale of our investment in Orion as previously discussed in the Events of 2002 section on page 23. This gain was partially offset by gains on the sale of securities in 2001 that had a positive impact in that period, including the sale of one million shares of our Orion investment as discussed above and lower results from our financial investments operation due to lower levels of investments and volatile equity markets during 2002. 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. Through June 30, 2002, we liquidated approximately 50% of our investment portfolio since the beginning of the year. Our remaining real estate 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 June 30, 2002, total fixed charges increased compared to the same period of 2001 mostly because of a higher level of debt outstanding. During the six months ended June 30, 2002, total fixed charges decreased compared to the same period of 2001 mostly because of lower short-term interest rates partially offset by a higher level of debt outstanding. Income Taxes ------------ During the quarter and six months ended June 30, 2002, our total income taxes increased compared to the same periods of 2001 mostly because of higher taxable income. 44 Financial Condition ------------------- Cash Flows ---------- Cash provided by operations was $335.5 million for the six months ended June 30, 2002 compared to $261.0 million in 2001. For the six months ended June 30, 2002, cash provided by investing activities was $295.5 million compared to cash used in investing activities of $568.5 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 the liquidation program associated with our investment portfolio and a decrease in capital spending due to the termination of all planned development projects. Cash used in financing activities for the six months ended June 30, 2002 was $450.4 million compared to cash provided of $236.6 million in 2001. The decrease during 2002 was primarily due to higher repayment of debt in 2002 and the issuance of common stock in 2001. 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, but are not limited to, 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 and established $1.28 billion of credit facilities during 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. In June 2002, Constellation Energy established a 364-day revolving credit facility totaling $640 million, and a $640 million three-year revolving credit facility. These two new facilities will support our issuances of commercial paper and letters of credit along with a previously established $188.5 million revolving credit facility that expires in June 2003. These facilities also can issue letters of credit up to approximately $1.1 billion. As of June 30, 2002, Constellation Energy had $257.4 million in outstanding letters of credit that results in approximately $1.2 billion of unused credit facilities. 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 $150.0 million in annual committed bank lines of credit and a $50 million bank revolving credit agreement to support its commercial paper program. The $50 million 364-day agreement expires in late 2002. As of June 30, 2002, BGE had no outstanding commercial paper, which results in $200.0 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 up to $25 million of receivables. In July 2002, BGE announced a partial call of $11.7 million principal amount of its 7 1/2% Series, due April 15, 2023 First Refunding Mortgage Bonds in connection with its annual sinking fund. Bonds called will be redeemed in whole or in part on August 28, 2002 at the price of 100% of principal, plus accrued interest from April 15, 2002 to August 28, 2002. Other Nonregulated Businesses ----------------------------- BGE Home Products & Services maintains a program to sell up to $50 million 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. 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. 45 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 51. Calendar Year Estimates 2002 2003 -------------------------------------------------- (In millions) Nonregulated Capital Requirements: Merchant Energy Construction program $139 $-- Steam generators 91 65 Environmental controls 67 16 Continuing requirements (including nuclear fuel) 315 199 -------------------------------------------------- Total Merchant Energy 612 280 Other Nonregulated 38 34 -------------------------------------------------- Total Nonregulated capital requirements 650 314 -------------------------------------------------- Utility Capital Requirements: Regulated electric 163 174 Regulated gas 60 56 -------------------------------------------------- Total Utility capital requirements 223 230 -------------------------------------------------- Total capital requirements $873 $544 ================================================== Table does not include amounts for the acquisition of NewEnergy. We discuss this acquisition in the Events of 2002 section on page 25. 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 2,200 megawatts of natural gas-fired peaking and combined cycle production facilities in various regions of North America. In the second quarter of 2002, our Rio Nogales facility and certain units of our Oleander facility were placed in service. 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 was completed at the end 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 the 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 15. 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 June 30, 2002, the outstanding lease balance plus other committed expenses was $582.9 million. 46 At the conclusion of the lease term in 2006, we have the following options: o renew the lease upon approval of the lessors, o elect to purchase the property for a price equal to the lease balance at the end of the term, or o request the lessor to sell the property. If we request the lessor to sell the property, we guarantee the sale proceeds up to approximately 83% of the lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based on the ultimate cost of construction and interest incurred during the construction period. 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. We expect to fund the NewEnergy acquisition with available sources of funding at the date of acquisition. 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 150% of the cash needed to meet the capital requirements for its operations, excluding cash needed to retire debt or fund corporate obligations. 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. BGE also participates in a cash pool with Constellation Energy as discussed in the Notes to Consolidated Financial Statements section on page 19. 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, sales of securities and assets, and/or from time to time equity contributions from Constellation Energy. 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 securities and 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 44. Committed Amounts ----------------- Our total contractual and contingent obligations as of June 30, 2002 are shown in the following table: Payments/Expiration ------------------------------------------------------ 2002 2003-2004 2005-2006 Thereafter Total ------------------------------------------------------------------------ (In millions) Contractual Obligations ----------------------- Short-term borrowings $15.5 $ -- $ -- $ -- $ 15.5 Nonregulated long-term debt* 7.2 49.2 301.4 2,145.3 2,503.1 BGE long-term debt* 342.7 438.1 508.0 920.0 2,208.8 BGE preference stock -- -- -- 190.0 190.0 Fuel and transportation 176.5 356.9 81.9 12.8 628.1 Purchased capacity and energy 27.4 48.6 35.7 89.2 200.9 Operating leases 7.1 76.7 61.6 164.5 309.9 Capital and loan commitments ** 56.2 20.4 -- -- 76.6 ------------------------------------------------------------------------ Total contractual obligations 632.6 989.9 988.6 3,521.8 6,132.9 ------------------------------------------------------------------------ Contingent Obligations ---------------------- Letters of credit 239.7 17.7 -- -- 257.4 Guarantees, net*** 566.2 89.8 688.4 214.4 1,558.8 ------------------------------------------------------------------------ Total contingent obligations 805.9 107.5 688.4 214.4 1,816.2 ------------------------------------------------------------------------ Total obligations $1,438.5 $1,097.4 $1,677.0 $3,736.2 $7,949.1 ======================================================================== *Amounts reflected in long-term debt maturities do not include $394 million investors may require us to repay early through put options and remarketing features. **Amounts related to capital expenditures are included for applicable periods in our capital requirements table on page 46. *** Guarantees in the above table are shown net of liabilities recorded at June 30, 2002 in our Consolidated Balance Sheets. 47 While we included our contingent obligations in the table on the previous page, 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 on the previous page. 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 on the previous page. The table on the previous page does not include the fixed payment portions of our mark-to-market energy assets and liabilities primarily related to capacity payments under tolling arrangements. We discuss the expected settlement terms of these contracts on page 36. Liquidity Provisions -------------------- We have certain agreements that contain provisions that would require additional collateral upon significant credit rating decreases in the Senior Unsecured Debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities. However, under counterparty contracts related to our origination and risk management operation, where we are obligated to post collateral, we estimate that we would have additional collateral obligations based on downgrades to the following credit ratings for our Senior Unsecured Debt: Credit Ratings Level Below Incremental Cumulative Downgraded Current Rating Obligations Obligations ------------------------------------------------------------- (In millions) BBB/Baa2 1 $ 50 $ 50 BBB-/Baa3 2 60 110 Below investment grade 3 405 515 At June 30, 2002, we had approximately $1.2 billion of unused credit facilities and $251.0 million of cash available to meet these potential requirements. However, 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 amounts specified above 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 14 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 on page 20. Item 3. Quantitative and Qualitative Disclosures About Market Risk ------------------------------------------------------------------ We discuss the following information related to our market risk: o financing activities and SFAS No. 133 hedging activities sections in the Notes to Consolidated Financial Statements beginning on page 14, o activities of our origination and risk management operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 32, and o changes to our business environment in the Business Environment section of Management's Discussion and Analysis beginning on page 27. 48 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 had until June 15, 2002 to respond. A show cause hearing was held on August 5, 2002 and the plaintiff did not appear. A hearing is scheduled for October 7, 2002 for the plaintiff to show cause why the case should not be dismissed. 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 565 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 beginning 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, 47 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 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer. MAPSA filed an appeal with the Maryland Court of Special Appeals. On April 1, 2002, the Maryland Court 49 of Special Appeals ruled against MAPSA on each of its arguments. MAPSA did not file an appeal to this decision. Accordingly, this matter is now closed. 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. 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) However, MAPSA filed several appeals of this decision with several courts. On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals. On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order. MAPSA filed an appeal with the Maryland Court of Special Appeals. On April 1, 2002, the Maryland Court of Special Appeals ruled against MAPSA on each of its arguments. MAPSA did not file an appeal to this decision. Accordingly, this matter is now closed. Other ----- McCray, et. al .v. Baltimore Gas and Electric Company-- On June 10, 2002, a suit was filed in the Circuit Court of Baltimore City, Maryland seeking a total of $585 million in compensatory and punitive damages from BGE as a result of a fire in a home that caused five fatalities. Electricity to the home was shut off. While discovery in this suit has not yet begun, BGE believes that this case is without merit. Item 4. Submission of Matters to a Vote of Security Holders ------- --------------------------------------------------- On May 24, 2002, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon: 1. All of the Directors nominated by Constellation Energy Group were elected as follows:
COMMON SHARES CAST: ------------------ For Against Abstain --- ------- ------- Roger W. Gale 136,957,982 9,105,134 3,919,330 Dr. Freeman A. Hrabowski, III 144,148,940 1,914,176 3,919,330 Nancy Lampton 144,352,057 1,711,059 3,919,330 Adm. Charles R. Larson * 144,749,102 1,314,014 3,919,330 Christian H. Poindexter 140,878,484 5,184,632 3,919,330
All other directors whose term of office continued after the date of this meeting are: James T. Brady James R. Curtiss Douglas L. Becker Edward J. Kelly, III Frank P. Bramble, Sr. Robert J. Lawless Beverly B. Byron Mayo A. Shattuck, III Edward A. Crooke Michael D. Sullivan * On July 5, 2002, Adm. Charles R. Larson resigned from the Board of Directors. 2. The ratification of PricewaterhouseCoopers, LLP as independent accountants was approved. With respect to holders of common stock, the number of affirmative votes cast was 143,619,000, the number of votes cast against was 5,266,496, and the number of abstentions was 1,251,706. 3. The proposal concerning approval of the executive long-term incentive plan was approved. With respect to holders of common stock, the number of affirmative votes cast was 131,608,867, the number of votes cast against was 15,771,163, and the number of abstentions was 2,758,239. 4. The proposal concerning approval of the executive annual incentive plan was approved. With respect to holders of common stock, the number of affirmative votes cast was 133,947,074, the number of votes cast against was 13,362,460, and the number of abstentions was 2,828,795. 5. The shareholder proposal concerning hiring Constellation Energy's auditors for non-audit work was defeated. With respect to holders of common stock, the number of affirmative votes cast was 16,550,514, the number of votes cast against was 111,279,666, and the number of abstentions was 3,904,137. 50 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, electricity, and emission allowances, 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, interest rates, availability of credit, liquidity, 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 distribution rates and revenues, demand for energy, or increase costs, including costs related to nuclear power plants, safety, or environmental compliance, o the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in applying mark-to-market accounting, such as variable contract quantities and the value of mark-to-market assets and liabilities determined using models, o losses on the sale or write down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets, o cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities, 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 June 30, 2002: None Filed 51 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: August 14, 2002 /s/ E. Follin Smith ---------------- --------------------------------------------- E. Follin Smith, Senior Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 52