-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, F7ldHKASRMO5EJkXNUuPQ/ui6jtBaBFsPMucSLkbMOuzl1qGxH5/+qD2a0YXUbRX 6rn12LqZ0PpBk9LkEr2mwQ== 0000950169-01-000114.txt : 20010402 0000950169-01-000114.hdr.sgml : 20010402 ACCESSION NUMBER: 0000950169-01-000114 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONSTELLATION ENERGY GROUP INC CENTRAL INDEX KEY: 0001004440 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 521964611 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-25931 FILM NUMBER: 1585825 BUSINESS ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345685 MAIL ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 FORMER COMPANY: FORMER CONFORMED NAME: CONSTELLATION ENERGY CORP DATE OF NAME CHANGE: 19951220 FORMER COMPANY: FORMER CONFORMED NAME: RH ACQUISITION CORP DATE OF NAME CHANGE: 19951205 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-01910 FILM NUMBER: 1585826 BUSINESS ADDRESS: STREET 1: 250 W PRATT ST CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345000 10-K 1 0001.txt CONSTELLATION ENERGY GROUP, INC. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K --------------- ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2000 Commission Exact name of registrant as specified in its IRS Employer file number charter Identification No. 1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND (States of incorporation) 250 W. PRATT STREET BALTIMORE, MARYLAND 21201 (Address of principal executive offices) (Zip Code) 410-234-5000 (Registrants' telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of Each Exchange Title of each class on Which Registered ------------------- ----------------------------- New York Stock Exchange, Inc. Constellation Energy Group, Inc. Common Chicago Stock Exchange, Inc. Stock--Without Par Value } Pacific Stock Exchange, Inc. 7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, } New York Stock Exchange, Inc. fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: Not Applicable 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 . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of February 28, 2001 was approximately $6,438,511,488 based upon New York Stock Exchange composite transaction closing price. CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 151,188,640 SHARES OUTSTANDING ON FEBRUARY 28, 2001. DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K Document Incorporated by Reference ----------------- ---------------------------------- III Certain sections of the Proxy Statement for Constellation Energy Group, Inc. for the Annual Meeting of Shareholders to be held on April 27, 2001.
Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form in the reduced disclosure format. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TABLE OF CONTENTS
Page ---- Forward Looking Statements................................. 1 PART I Item 1 -- Business................................................... 1 Overview.................................................. 1 Domestic Merchant Energy Business ........................ 3 BGE....................................................... 9 Electric Business........................................ 10 Electric Operating Statistics............................ 12 Gas Business............................................. 12 Gas Operating Statistics................................. 14 Franchises............................................... 15 Other Nonregulated Businesses ............................ 15 Consolidated Capital Requirements......................... 16 Environmental Matters..................................... 16 Employees................................................. 19 Item 2 -- Properties................................................. 19 Item 3 -- Legal Proceedings.......................................... 19 Item 4 -- Submission of Matters to a Vote of Security Holders........ 20 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)................................. 20 PART II Item 5 -- Market for Registrant's Common Equity and Related Shareholder Matters....................................... 21 Item 6 -- Selected Financial Data.................................... 22 Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 24 Item 7A -- Quantitative and Qualitative Disclosures About Market Risk..................................................... 43 Item 8 -- Financial Statements and Supplementary Data................ 44 Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 83 PART III Item 10 -- Directors and Executive Officers of the Registrant......... 83 Item 11 -- Executive Compensation..................................... 83 Item 12 -- Security Ownership of Certain Beneficial Owners and Management................................................ 83 Item 13 -- Certain Relationships and Related Transactions............. 83 PART IV Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................................... 84 Signatures............................................................. 88
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: . satisfaction of all the conditions precedent to the closing on the purchase of the Nine Mile Point nuclear power plants, including obtaining all regulatory approvals, . obtaining all regulatory approvals necessary to close on the investment by an affiliate of the Goldman Sachs Group, Inc. in our domestic merchant energy business and complete the separation of our domestic merchant energy business from our remaining businesses, . satisfaction of all conditions precedent to the transaction with Goldman Sachs, . general economic, business, and regulatory conditions, . the pace and nature of deregulation nationwide (including the status of the California markets), . competition, . energy supply and demand, . federal and state regulations, . availability, terms, and use of capital, . nuclear and environmental issues, . weather, . implications of the Restructuring Order issued by the Maryland PSC, including the outcome of the appeal, . commodity price risk, . operating our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause, . loss of revenue due to customers choosing alternative suppliers, . higher volatility of earnings and cash flows, . increased financial requirements of our nonregulated subsidiaries, . inability to recover all costs associated with providing electric retail customers service during the electric rate freeze period, . implications from the transfer of BGE's generation assets and related liabilities to nonregulated subsidiaries of Constellation Energy, including the outcome of the appeal of the Maryland PSC's Order regarding the transfer of generation assets, and . force majeure events (events beyond our control), such as: acts of nature, changes of laws, labor strikes and work stoppages, especially as they could impact plant construction or operation. 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 Securities and Exchange Commission (SEC) for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report. - -------------------------------------------------------------------------------- PART I Item 1. Business Overview Constellation Energy(R) Group, Inc. (Constellation Energy) is a holding company whose businesses consist primarily of a domestic merchant energy business focused mostly on power marketing and merchant generation in North America, and Baltimore Gas and Electric Company (BGE(R)), a regulated electric and gas public utility distribution company. Constellation Energy was incorporated in Maryland on September 25, 1997. On April 30, 1999, Constellation Energy became the holding company for BGE and its subsidiaries through a share exchange. 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. Effective July 1, 2000, electric generation was deregulated in Maryland. In anticipation of deregulation, during the first quarter of 2000, we combined our wholesale power marketing operation with our domestic plant development and operation activities to form a domestic merchant energy business. Additionally, on July 1, 2000, BGE transferred all of its generation assets and related liabilities at book value to two new nonregulated subsidiaries of our domestic merchant energy business--Calvert Cliffs Nuclear Power Plant,(TM) Inc. and Constellation Power Source Generation,(TM) Inc. We discuss the deregulation of electric generation in Item 7. Management's Discussion and Analysis--Current Issues. We also formed a nonregulated holding company, Constellation Power Source Holdings,(TM) Inc. that oversees: . the wholesale power marketing and risk management activities of Constellation Power Source,(TM) Inc., . the domestic power projects of Constellation Investments,(TM) Inc. and Constellation Power,(TM) Inc. and subsidiaries, . the fossil and hydroelectric generating assets of Constellation Power Source Generation. 1 As a result of these changes, our domestic merchant energy business includes the operations of Constellation Power Source Holdings, the nuclear generating assets of Calvert Cliffs Nuclear Power Plant, Inc., and the nuclear consulting services of Constellation Nuclear,(TM) LLC. BGE is a regulated electric and gas public utility distribution company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland. BGE was incorporated in Maryland in 1906. BGE's electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2.7 million. BGE's gas service territory includes an area of approximately 800 square miles with an estimated population of 2.0 million. There are no municipal or cooperative wholesale customers within BGE's service territory. Our other nonregulated businesses include the: . Latin American power projects of Constellation Power and subsidiaries, . energy products and services of Constellation Energy Source,(TM) Inc., . home products, commercial building systems, and residential and small commercial electric and gas retail marketing of BGE Home Products & Services,(TM) Inc. and subsidiaries, . a general partnership, in which BGE is a partner, of District Chilled Water General Partnership (ComfortLink(R)) that provides cooling services for commercial customers in Baltimore, . financial investments of Constellation Investments, and . real estate holdings and senior-living facilities of Constellation Real Estate Group,(TM) Inc. Strategy Customer choice and regulatory change significantly impact our business. In response to these, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going forward, prior to separating into two companies, we expect to derive almost two-thirds of our earnings from our domestic merchant energy business. While BGE continues to be regulated and to deliver electricity and natural gas through its core distribution business, our primary growth strategies center on the nonregulated domestic merchant energy business with the objective of providing new sources of earnings growth. On October 23, 2000, we announced three initiatives to advance our growth strategies. The first initiative is that we entered into an agreement (the "Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a 17.5% equity interest in our domestic merchant energy business, which will be consolidated under a single holding company ("Holdco"). Goldman Sachs will also acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to certain adjustments). The warrant is exercisable six months after Holdco's common stock becomes publicly available. The amount of common stock which Goldman Sachs may receive upon exercise will be equal to the excess of the market price of Holdco's common stock at the time of exercise over the exercise price of $60 per share for all the stock subject to the warrant, divided by the market price. Holdco may at its option pay Goldman Sachs such excess in cash. Goldman Sachs is acquiring its interest and the warrant in exchange for $250 million in cash (subject to adjustment in certain instances) and certain assets related to our power marketing operation. At closing, Goldman Sachs' existing services agreement with our power marketing operation will terminate. The second initiative is a plan to separate our domestic merchant energy business from our remaining businesses. The separation will create two stand- alone, publicly traded energy companies. One will be a merchant energy business engaged in wholesale power marketing and generation under the name "Constellation Energy Group" after the separation. The other will be a regional retail energy delivery and energy services company, BGE Corp., which will include BGE, our other nonregulated businesses, and our investment in Orion Power Holdings, Inc. ("Orion"). As a result of the separation, shareholders will continue to own all of Constellation Energy's current businesses through their ownership of the stock of the new Constellation Energy Group and of BGE Corp. The third initiative is a change in our common stock dividend policy effective April 2001. In a move closely aligned with our separation plan, effective April 2001, our annual dividend is expected to be set at $.48 per share. After the separation, BGE Corp. expects to pay initial annual dividends of $.48 per share. Constellation Energy Group, as a growing merchant energy company, initially expects to reinvest its earnings in order to fund its growth plans and not to pay a dividend. The closing of the transaction with Goldman Sachs and the separation are subject to customary closing conditions and contingent upon obtaining regulatory approvals and a Private Letter Ruling from the Internal Revenue Service regarding certain tax matters. We expect to complete the transaction and separation by mid to late 2001. At the date of this report, we received approval from the Federal Energy Regulatory Commission (FERC). We discuss these strategic initiatives further in our Report on Form 8-K and exhibits filed with the SEC on October 23, 2000. Currently, our domestic merchant energy business controls over 9,000 megawatts (MW) of generation. In December 2000, we announced that a subsidiary of Constellation Nuclear will purchase 1,550 MW of the 1,757 MW total generating capacity of the Nine Mile Point nuclear power plant located in Scriba, New York. The total purchase price, including 2 fuel, is $815 million. We discuss the planned acquisition of the Nine Mile Point power plant in more detail in Note 10 to Consolidated Financial Statements. We also are constructing generating facilities representing 1,100 MW of natural gas-fired peaking capacity in the Mid-Atlantic and Mid-West regions which are expected to be operational by the summer of 2001. An additional 6,700 MW of natural gas-fired peaking and combined cycle production facilities in various regions of North America are scheduled for completion in 2002 and beyond. By 2005, our domestic merchant energy business expects to control approximately 30,000 MW through the construction or purchase of additional nuclear and non-nuclear generation assets and through contractual arrangements. We decided to exit the Latin American portion of our operation as a result of our concentration on domestic merchant energy. Currently, we are actively seeking a buyer for the Latin American portion of our business and are working toward completing our exit strategy in 2001. We also might consider one or more of the following strategies: . the complete or partial separation of our transmission and distribution functions, . mergers or acquisitions of utility or non-utility businesses, and . sale of generation assets or one or more businesses. Operating Segments The percentages of revenues, net income, and assets attributable to our operating segments are shown in the tables below. We present information about our operating segments, including certain nonrecurring items, in Note 2 to Consolidated Financial Statements. Effective with the first quarter of 2000, we revised our operating segments to reflect the realignments of our organization as discussed in the Overview section. Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the domestic merchant energy business segment. Prior to that date, the financial results are included in the regulated electric segment.
Unaffiliated Revenues ----------------------------------------- Domestic Merchant Regulated Regulated Other Energy Electric Gas Nonregulated -------- --------- --------- ------------ 2000 11% 55% 15% 19% 1999 6 60 12 22 1998 4 66 13 17 Net income(1) ----------------------------------------- Domestic Merchant Regulated Regulated Other Energy Electric Gas Nonregulated -------- --------- --------- ------------ 2000 60% 29% 9% 2% 1999 16 81 10 (7) 1998 17 85 9 (11)
Total Assets ----------------------------------------- Other Domestic Nonregulated Merchant Regulated Regulated & Corp. Energy Electric Gas Items -------- --------- --------- ------------ 2000 55% 28% 8% 9% 1999 13 65 9 13 1998 9 67 10 14
(1) Excludes an extraordinary charge of $66.3 million recorded in 1999 related to electric restructuring as discussed in Note 4 to Consolidated Financial Statements. Domestic Merchant Energy Business Introduction Our domestic merchant energy business engages primarily in generation and power marketing in North America. We integrate our electric generation, risk management, and marketing operations to meet our customers' energy needs in the wholesale energy market. Our goal is to become a leading merchant energy business in North America. We plan to continue our growth through the acquisition, development, and operation of power plants in our targeted markets. We also intend to capitalize on our ability to integrate power plants with the marketing of energy products and the management of market risk associated with these products. We plan to implement our strategy through the development of new power plants, acquisition of power assets competitively positioned in targeted markets, contractual arrangements for the control of generation capacity, and expansion of our marketing and risk management activities. Currently, our domestic merchant energy business controls over 9,000 MW of generation. By 2005, our domestic merchant energy business expects to control approximately 30,000 MW through the construction or purchase of additional nuclear and non-nuclear generation assets and through contractual arrangements. Our domestic merchant energy business experiences substantial competition from diversified energy companies, merchant generation companies, utilities, independent power producers, and power marketers. Competition is based on the price and availability of the commodities, services delivered, and the quality and reliability of services provided. Weather conditions in the different regions of North America influence the financial results of our domestic merchant energy business. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. However, all regions of North America typically do not experience extreme weather conditions at the same time. Since the majority of our generating plants currently are located in the PJM (Pennsylvania-New Jersey-Maryland) Interconnection, our financial results are affected, to a greater extent, by weather conditions in this area. Current weather conditions also can affect the forward market price of 3 energy commodity and derivative contracts used by our power marketing operation that are accounted for on a mark-to-market basis. To the extent that our power marketing operation purchases and sells such contracts, our financial results could be influenced by the impact that weather conditions have on the market price of such contracts. Delays in, or the ultimate form of, deregulation of electric generation in various states may affect our domestic merchant energy business strategy. Our domestic merchant energy business has $297.9 million invested in power projects that sell 142 MW of electricity in California under power purchase agreements as discussed in Note 10 to Consolidated Financial Statements, under the heading California Power Purchase Agreements. The counterparties to the agreements are two California investor-owned utilities. Due to various factors, including shortage of generation and the high cost of natural gas, these utilities' financial condition was severely impacted because they were paying more for power than they were allowed to recover from their customers under the deregulation plan in California. As a result, these utilities have not been able to maintain current payments for the power they purchased to meet their customers' energy needs and the credit ratings of these utilities were downgraded below investment grade. The governor and legislature of California have undertaken emergency actions to stabilize the financial condition of the two utilities by purchasing power on behalf of these utilities and pursuing legislation that should permit the utilities to pay their power costs. In the meantime, these utilities have not been paying our California projects in full for power supplied to them from December 2000. As of the date of this report, our portion of the amount due from these utilities is approximately $42 million. While we expect to be paid for this power, we cannot predict when payment will occur or if full payment will be received. We have taken reserves in amounts we believe to be reasonable under the circumstances. On March 27, 2001, the California Public Utilities Commission issued an order for an immediate retail rate increase. Accordingly, we expect that this order should enable these utilities to pay us for all future power supplied to these utilities. However, if the ultimate resolution of the events in California prevents the collection of unpaid balances under power purchase agreements by some or all of our projects, it could have a material impact on our financial results. In light of California's shortage of generation, we recently signed an agreement with the California Department of Water Resources for the sale of electricity beginning April 2001 through June 2003. We also signed an agreement with the California Department of Water Resources for the output of our High Desert I plant beginning July 2003 through September 2011 on a unit contingent basis (i.e., if the output is not available because the plant is not operating, there is no requirement to provide output from other sources.) We discuss our credit and other exposures related to the issues in California in Item 7. Management's Discussion and Analysis-Current Issues section. Domestic Generation We have operated in the nonregulated power markets since 1985. At December 31, 2000, we owned about 6,550 MW of generation capacity, and have over 9,000 MW under development, in construction, or pending acquisition. We cannot provide assurance that these projects or pending acquisitions will be completed. Effective July 1, 2000, BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. These two units are our largest generating units, totaling 1,685 MW, and are located in PJM. In March 2000, Calvert Cliffs became the first nuclear power plant in the United States to achieve license renewal. The Nuclear Regulatory Commission (NRC) approved a twenty-year license renewal for both units of Calvert Cliffs, extending the license for Unit 1 to 2034 and for Unit 2 to 2036. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. These plants provide electricity from a variety of fuels (coal, oil, gas and water) that total 4,554 MW and are located in PJM. In total, these generating assets represent about 6,240 MW of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion. The output of these plants is managed by our power marketing operation. We discuss our power marketing operation in the Power Marketing section. Constellation Power, Inc. and subsidiaries holds up to a 50% ownership interest in 28 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities and are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from, or not subject to, the Public Utility Holding Company Act of 1935. Projects totaling approximately $51.8 million of assets are located in the East and $419.8 million of assets are located in the West. Each electric generating plant sells its output to a local utility under long-term contracts. 4 The following table describes our generating and processing facilities.
Installed % Owned Primary Plant Location Capacity (MW) Owned Capacity (MW) Fuel -------------------- ------------------------------ ---------------------- ----- ---------------------- ------------ (at December 31, 2000) (at December 31, 2000) Generating Facilities Nuclear Calvert Cliffs Calvert Co., MD 1,685 100.0 1,685 (A) Nuclear Fossil Steam ----- Brandon Shores Anne Arundel Co., MD 1,300 100.0 1,300 (A) Coal Herbert A. Wagner Anne Arundel Co., MD 1,006 100.0 1,006 (A) Coal/Oil/Gas Charles P. Crane Baltimore Co., MD 385 100.0 385 (A) Coal Gould Street Baltimore City, MD 104 100.0 104 (A) Oil/Gas Riverside Baltimore Co., MD 78 100.0 78 (A) Gas Keystone Armstrong and Indiana Cos., PA 1,711 21.0 359 (A),(B) Coal Conemaugh Indiana Co., PA 1,711 10.6 181 (A),(B) Coal ACE Trona, CA 102 22.5 23 (C) Coal Jasmin Kern Co., CA 33 50.0 17 (C) Coal POSO Kern Co., CA 33 50.0 17 (C) Coal ----- ----- Total Steam 6,463 3,470 Combustion Turbine ------------------ Perryman Harford Co., MD 350 100.0 350 Oil/Gas Notch Cliff Baltimore Co., MD 128 100.0 128 Gas Westport Baltimore City, MD 121 100.0 121 Gas Riverside Baltimore Co., MD 173 100.0 173 Oil/Gas Philadelphia Road Baltimore City, MD 64 100.0 64 Oil Charles P. Crane Baltimore Co., MD 14 100.0 14 Oil Herbert A. Wagner Anne Arundel Co., MD 14 100.0 14 Oil ----- ----- Total Combustion Turbine 864 864 (A) Hydroelectric Safe Harbor Safe Harbor, PA 416 66.7 277 (A) Hydro Malacha Muck Valley, CA 32 50.0 16 (C) Hydro ----- ----- Total Hydroelectric 448 293 Alternative Mammoth Lakes G-1 Mammoth Lakes, CA 8 50.0 4 Geothermal Mammoth Lakes G-2 Mammoth Lakes, CA 12 50.0 6 Geothermal Mammoth Lakes G-3 Mammoth Lakes, CA 12 50.0 6 Geothermal Ormesa II Imperial Valley, CA 17 50.0 9 Geothermal Puna I Hilo, HI 30 50.0 15 Geothermal Soda Lake I Fallon, NV 3 50.0 2 Geothermal Soda Lake II Fallon, NV 14 50.0 7 Geothermal Stillwater Fallon, NV 11 50.0 6 Geothermal SEGS IV Kramer Junction, CA 30 12.0 4 Solar SEGS V Kramer Junction, CA 30 4.0 1 Solar SEGS VI Kramer Junction, CA 30 9.0 3 Solar Chinese Station Sonora, CA 22 50.0 11 Biomass Fresno Fresno, CA 24 50.0 12 Biomass Rocklin Placer Co., CA 24 50.0 12 Biomass Central Wayne Dearborn, MI 22 50.0 11 Municipal Solid Waste Colver Colver Township, PA 110 50.0 55 Waste Coal Panther Creek Nesquehoning, PA 83 50.0 42 Waste Coal Sunnyside Sunnyside, UT 51 50.0 26 Waste Coal ----- ----- Total Alternative 533 232 (C) ----- ----- Total Generating Facilities 9,993 6,544 ===== =====
(A) Represent the generating assets that were transferred from BGE to nonregulated subsidiaries of Constellation Energy on July 1, 2000. (B) These totals reflect our proportionate interest and entitlement to capacity from Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh. (C) These totals reflect our proportionate interest in the entities that own these plants. 5
Installed % Owned Primary Plant Location Capacity (MW) Owned Capacity (MW) Fuel ------------- -------------- ---------------------- ----- ---------------------- ------------------ (at December 31, 2000) (at December 31, 2000) Processing Facilities Gary PCI Gary, IN -- 12.5 -- Coal Processing A/C Fuels Hazelton, PA -- 50.0 -- Coal Processing PC Synfuel VA I Appalachia, VA -- 16.7 -- Synfuel Processing PC Synfuel WV I Charleston, WV -- 16.7 -- Synfuel Processing PC Synfuel WV II Nettie, WV -- 16.7 -- Synfuel Processing PC Synfuel WV III Mayberry, WV -- 16.7 -- Synfuel Processing
Our domestic generation operation currently plans to construct generating facilities representing about 7,800 MW of natural gas-fired peaking capacity and combined cycle production facilities in various regions in North America in 2001 and beyond. The output of these plants will be used to meet the energy requirements of customers in the wholesale energy market. The following table describes the generating facilities that currently are under construction or are scheduled to begin construction shortly:
Target In Capacity Primary Percent Service Plant Location (MW) Type Fuel Controlled Date - ----------- ------------ -------- ------------ ------- ---------- --------- University Park Chicago, IL 300 Combustion Turbine Gas 100 Summer 2001 Wolf Hills Bristol, VA 250 Combustion Turbine Gas 100 Summer 2001 Handsome Lake Rockland Twp, PA 250 Combustion Turbine Gas 100 Summer 2001 Big Sandy Neal, WV 300 Combustion Turbine Gas 100 Summer 2001 Rio Nogales Seguin, TX 800 Combined Cycle Gas 100 Summer 2002 Holland Energy Shelby Co., IL 665 Combined Cycle Gas 100 Summer 2002 Oleander Brevard Co., FL 680 Combustion Turbine Gas 100 Summer 2002 High Desert I Victorville, CA 750 Combined Cycle Gas 100 Summer 2003 ----- Total 3,995
We also have projects that currently are under development in other strategic areas that include Texas, Wisconsin, Massachusetts, Florida, and California. - -------------------------------------------------------------------------------- Planned Acquisition On December 12, 2000, we announced that a subsidiary of Constellation Nuclear will purchase 1,550 MW of the 1,757 MW total generating capacity of the Nine Mile Point nuclear power plant, located in Scriba, New York. The subsidiary of Constellation Nuclear will buy 100 percent of Unit 1 and 82 percent of Unit 2 for $815 million, including $78 million for fuel. The sale is expected to close in mid-2001 upon receipt of all necessary regulatory approvals. Key regulatory approvals are required from the NRC, FERC, and the New York State Public Service Commission. The terms of the transaction include power purchase agreements, whereby we have agreed to sell 90 percent of our share of the Nine Mile Point plant's output back to the sellers for approximately 10 years at an average price of nearly $35 per megawatt-hour (MWH) over the term of the power purchase agreements on a unit contingent basis. We discuss this planned acquisition in more detail in Note 10 to Consolidated Financial Statements. Fuel Sources Our power plants use diverse fuel sources. At December 31, 2000, our fuel mix based on capacity owned was:
Fuel Percentage - ---- ---------- Nuclear.............................................................. 26% Coal................................................................. 42 Oil.................................................................. 13 Renewable and Alternative(1)......................................... 8 Dual(2).............................................................. 6 Natural Gas.......................................................... 5
(1) Includes solar, geothermal, hydro, biomass, and waste-to-energy. (2) Switches between natural gas and oil. 6 Nuclear The two units at Calvert Cliffs produce electricity at a relatively low cost. As a result, the costs of replacement energy associated with outages at these units can be significant. If an unplanned outage were to occur during the summer or winter when demand was at a high level, the replacement power costs could have a material adverse impact on our financial results. We will use appropriate risk management techniques consistent with our business plan and policies in an effort to address this issue. The output at Calvert Cliffs over the past five years was as follows:
Generation Capacity MWH Factor ---------- -------- 2000........................................................ 13,826,046 93% 1999........................................................ 13,309,306 91 1998........................................................ 13,326,633 91 1997........................................................ 13,133,441 90 1996........................................................ 12,069,937 82
The supply of fuel for nuclear generating stations includes the: . purchase of uranium concentrates, . conversion to uranium hexafluoride, . enrichment of uranium hexafluoride, and . fabrication of nuclear fuel assemblies. Uranium Concentrates: We have, either in inventory or under contract, sufficient quantities of uranium to meet 100% of our requirements through 2002 and 25% through 2004. Conversion:We have contractual commitments providing for the conversion of uranium concentrates into uranium hexafluoride that will meet approximately 75% of our requirements through 2004. Enrichment:We have a contract with the U.S. Enrichment Corporation that provides approximately 50% of our enrichment requirements to 2004. Fuel Assembly Fabrication: We have contracted for the fabrication of fuel assemblies for reloads required through 2013. The nuclear fuel market is competitive and we do not anticipate any problem in meeting our requirements. Storage of Spent Nuclear Fuel--Federal Facilities: Under the Nuclear Waste Policy Act of 1982 (the 1982 Act), we contracted with the United States Department of Energy (DOE) to place spent fuel discharged from Calvert Cliffs into a federal repository. Such facilities do not currently exist, and, consequently, must be developed and licensed. We cannot predict when such facilities will be available. However, the 1982 Act required the DOE to accept spent fuel starting in 1998. We cannot predict the ultimate cost of disposing spent fuel. However, the 1982 Act assesses a 0.1 cent (one mill) per kilowatt- hour fee on nuclear electricity generated and sold to help pay for spent fuel disposal. We estimate this fee to be approximately $13 million for Calvert Cliffs each year based on expected operating levels. Fees are deposited into the Nuclear Waste Fund. These costs are paid by Calvert Cliffs Nuclear Power Plant, Inc. In December 1996, the DOE notified us and other nuclear utilities that it would not be able to meet the 1998 deadline for accepting spent fuel. We participated in litigation, along with 36 other utilities, against the DOE. The litigation, titled Northern States Power, et al. v. DOE, was filed January 31, 1997 in the United States Court of Appeals for the D.C. Circuit. That court has original jurisdiction under the 1982 Act. The utilities asked the court to allow them to pay fees that formerly went directly to the DOE for deposit into the Nuclear Waste Fund, into escrow instead. Among other remedies, the utilities also asked the court to force the DOE to submit a program with milestones illustrating how it would meet the deadline for accepting spent nuclear fuel, and a monthly report to allow the utilities to monitor the DOE's progress. On November 14, 1997, the court ordered the DOE to comply with its unconditional obligation under the 1982 Act to dispose of spent fuel. The court did not grant the utilities the remedies sought, stating that adequate contractual and statutory remedies already existed. The DOE and several utilities filed separate motions for reconsideration with the court, which were denied. The DOE's request for review to the U.S. Supreme Court was also denied. We are currently evaluating our contractual options in light of the court's decision. We cannot currently estimate the total costs we will incur as a result of the DOE's failure to meet the 1998 deadline. Storage of Spent Nuclear Fuel--On-Site Facility: We have a license from the NRC to operate an on-site independent spent fuel storage facility. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through the year 2006. In addition, we can expand our temporary storage capacity to meet future requirements until federal storage is available. Cost for Decommissioning Uranium Enrichment Facilities: The Energy Policy Act of 1992 (the 1992 Act) contains provisions requiring domestic nuclear utilities to contribute to a fund for decommissioning and decontaminating the DOE's uranium enrichment 7 facilities. These contributions are payable by BGE generally over a fifteen- year period with escalation for inflation and are based upon the amount of uranium enriched by the DOE for each utility through 1992. The 1992 Act provides that these costs are recoverable through BGE's service rates. Information about the cost of decommissioning is discussed in Note 1 to Consolidated Financial Statements. Cost for Decommissioning Calvert Cliffs: Calvert Cliffs Nuclear Power Plant, Inc., is liable for the decommissioning costs of Calvert Cliffs and costs associated with the on-site independent spent fuel storage facilities. On July 1, 2000, BGE transferred the trust fund established to decommission Calvert Cliffs and the on-site spent fuel storage facility to Calvert Cliffs Nuclear Power Plant, Inc. Under the Restructuring Order issued by the Maryland Public Service Commission (Maryland PSC), BGE is authorized to collect from customers $520 million in 1993 dollars, adjusted for inflation, for the decommissioning of Calvert Cliffs. BGE is passing the amount collected from its customers to Calvert Cliffs Nuclear Power Plant, Inc. We must refund any amounts collected from BGE customers at the time of decommissioning that is in excess of the amount authorized to be collected by the Restructuring Order. We discuss the Restructuring Order in the Electric Regulatory Matters and Competition-- Restructuring Order section. Coal We get most of our coal under supply contracts with mining operators, and we get the rest through spot purchases. We believe that we will be able to renew supply contracts as they expire or enter into similar contracts with other coal suppliers. Our primary coal-burning facilities have the following requirements:
Annual Coal Requirement Special Coal (tons) Restrictions ----------- ---------------------- Brandon Shores Sulfur content less Units 1 and 2 (combined).................... 3,500,000 than 0.8% Crane Low ash melting Units 1 and 2 (combined).................... 800,000 temperature Wagner Sulfur content no more Units 2 and 3 (combined).................... 1,000,000 than 1%
Coal deliveries to these facilities are made by rail and barge. The coal we use is produced mostly from mines located in central and northern Appalachia. The majority of the annual coal requirements for the Keystone plant are under contract from Rochester and Pittsburgh Coal Company. The remainder of the Keystone plant and all of the Conemaugh plant annual coal requirements are purchased from local suppliers on the open market. The sulfur restrictions on coal are approximately 2.5% for the Keystone plant and approximately 3.5% for the Conemaugh plant. The annual coal requirements for the ACE, Jasmin, and POSO plants, which are located in California, are supplied under contracts with mining operators. Each plant is restricted to coal with sulfur content less than 4%. Oil Under normal burn practices, our requirements for residual fuel oil (No. 6) amount to approximately 1,500,000 to 2,000,000 barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made directly into our barges from the suppliers' Baltimore Harbor marine terminal for distribution to the various generating plant locations. We also require approximately 5,000,000 to 6,000,000 gallons of distillates (No. 2 oil and kerosene) annually. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices to meet our requirements. Gas We purchase natural gas and transportation, as necessary, for electric generation at certain plants and to provide ignition and banking at certain plants. Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is purchased under contracts with suppliers on the spot market. We believe that we will be able to obtain adequate quantities of gas to meet our requirements. Power Marketing Constellation Power Source, Inc. (CPS), formed in 1997, provides power marketing and risk management services to wholesale customers in North America through the purchase and sale of electric power, other energy commodities and related derivative contracts. CPS was ranked by Power Markets Weekly as a top ten power marketer in the United States based on MWH sold in 2000. CPS purchases electric power by several methods, including: . through bilateral agreements with third parties, . from regional power pools, or . from affiliates in the domestic merchant energy business. CPS sells the electric power it purchases to customers such as utilities, municipalities, cooperatives and other resellers, structuring the transactions to meet each customer's diverse needs. 8 CPS supplies the standard offer electric supply service to BGE as discussed in Item 7. Management's Discussion and Analysis--Current Issues and to several distribution utilities in New England. CPS sold 162,349,997 MWH of electric power in 2000, including sales to BGE, 69,787,986 MWH in 1999, and 27,608,080 MWH in 1998, its first full year of operation. Excluding BGE, no one customer or small group of customers accounts for a material portion of CPS' electric power purchases or sales. CPS' goal is to be a premier provider of energy products and risk management services to wholesale customers throughout North America. To accomplish this goal, CPS focuses its activities on structuring transactions to meet customers' specific energy needs and providing risk management services to wholesale customers. This includes optimizing the value of generating assets owned by affiliates. We believe that our energy marketing and risk management expertise and strong risk controls are essential to maximize the value of our generating assets in the highly competitive wholesale energy market. We expect CPS to continue to establish itself as a leading national merchant energy company by leveraging its marketing and risk management expertise to pursue opportunities presented by the continuing deregulation of the North American energy markets. CPS engages in trading activities in order to manage its portfolio of energy purchases and sales to customers through structured transactions, and to take advantage of arbitrage opportunities that exist across different markets. These activities involve the use of a variety of instruments, including: .forward contracts, which commit it to purchase or sell energy commodities in the future, .swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity, .options contracts, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price, and .futures contracts, which are exchange traded standardized commitments to purchase or sell a commodity or financial instrument, or make a cash settlement, at a specified price and future date. Active portfolio management allows CPS to manage and hedge its fixed price purchase and sale commitments; provide fixed-price commitments to customers and suppliers; reduce exposure to the volatility of market prices; and hedge fuel requirements at power generation facilities. CPS' trading activities expose it to market and credit risk. CPS monitors and controls its risk exposure through separate but complementary financial, operational, and credit reporting systems. Our Board of Directors establishes parameters for the risks that CPS undertakes, which are monitored daily by management. In addition, CPS maintains a segregation of duties, with credit review and risk monitoring functions performed by groups that are independent from revenue producing groups. CPS is exposed to the risk that fluctuating market prices may adversely affect its, or our, financial results. For additional information on market and credit risk, see Item 7. Management's Discussion and Analysis--Market Risk. Nuclear Consulting Services Constellation Nuclear Services, Inc. (CNS) was formed in 1999 to provide nuclear license renewal related services to the utility industry. In addition to nuclear license renewal, CNS also provides plant aging mitigation services including: spent fuel management, dry fuel storage, steam generation life optimization, and project management and engineering. BGE BGE is a regulated electric and gas public utility distribution company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland. BGE's electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2.7 million. BGE's gas service territory includes an area of approximately 800 square miles with an estimated population of 2.0 million. Our electric and gas revenues come from many customers--residential, commercial, and industrial. In 2000, our largest electric customer provided 2.4% of our total electric revenues. In 2000, our largest gas customer provided 0.7% of our total gas revenues. As discussed below, BGE's regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice in Maryland. 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. 9 Electric Business Electric Regulatory Matters and Competition Restructuring Order On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 4 to Consolidated Financial Statements. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel to lower our electric base rates. The major provisions of the Restructuring Order are discussed in Note 4 to Consolidated Financial Statements. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000: .All customers, except a few commercial and industrial companies that have signed contracts with BGE, can choose their electric energy supplier. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. .BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year. These rates will not change before July 2006. .BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. In total, these generating assets represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion. .BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power Plant, Inc. and $231 million to Constellation Power Source Generation of tax-exempt debt related to the transferred assets. Also, Constellation Power Source Generation issued approximately $366 million in unsecured promissory notes to BGE. Repayments of the notes by Constellation Power Source Generation will be used exclusively to service the current maturities of certain BGE long-term debt. .BGE transferred equity associated with the generating assets to Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation. .The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE were also assumed by these subsidiaries. Standard Offer Service Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period through June 30, 2006 for those customers that do not choose an alternate supplier. In addition, the electric fuel rate was discontinued effective July 1, 2000. CPS provides BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Thereafter, BGE will competitively bid the energy and capacity for those customers electing to receive energy from BGE. We are evaluating alternatives to minimize the market risk after June 30, 2003. We discuss the market risk of our regulated electric business in more detail in Item 7. Management's Discussion and Analysis--Market Risk. Prior to July 1, 2000, BGE deferred (included as an asset or liability on the Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) the difference between its actual costs of fuel and energy and what it 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 BGE's 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. BGE is collecting this accumulated difference from customers over the twelve-month period beginning October 2000. 10 BGE's electric transmission and distribution business continues to be regulated by the Maryland PSC although electric delivery rates are fixed until June 30, 2004 for industrial and commercial customers and until June 30, 2006 for residential customers. However, electric transmission and distribution utilities are facing competition from alternative energy sources that include on-site generation and cogeneration projects. In future years, electric transmission and distribution utilities could face competition from emerging technologies that include fuel cells and solar panels. Electric Load Management BGE implemented various programs for use when system-operating conditions or market economics indicate that a reduction in load would be beneficial. We refer to these programs as active load management programs. These programs include: .customer-owned generation and curtailable service for large commercial and industrial customers, .air conditioning control for residential and commercial customers, and .residential water heater control. BGE generally activates these programs on summer days when demand and/or wholesale prices are relatively high. The reduction in the summer 2000 peak load from active load management was approximately 425 MW. The potential reduction in the summer 2001 peak load from active load management is expected to be approximately425 MW. Transmission Facilities Our transmission facilities are connected to those of neighboring utility systems as part of the PJM. Under the PJM agreement, we use the interconnected facilities for substantial energy interchange and capacity transactions as well as emergency assistance. In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs). The regulations require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in a RTO. FERC also identified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered a RTO. According to Order 2000, a public utility that is a member of an existing transmission entity that has been approved by FERC as in conformance with the Independent System Operator (ISO) principles set forth in the FERC Order No. 888, such as BGE through its membership in the PJM, was required to make a filing no later than January 15, 2001. PJM and the joint transmission owners, including BGE, made that filing on October 11, 2000. That filing explained the extent to which PJM met the minimum characteristics and functions of a RTO, and explained its plans with respect to conforming to these characteristics and functions. As a member of PJM, an existing ISO, BGE does not expect to be materially impacted by Order 2000. However, we are appealing two requirements of Order 2000 whereby: .we would have to go through PJM to make a filing with FERC to change our transmission rates, and .we would have to transfer operational control of our transmission facilities to PJM. The U.S. Supreme Court agreed to hear an appeal by others of FERC Order 888. We cannot predict the outcome of this appeal or the impact on BGE at this time. 11 Electric Operating Statistics
Year Ended December 31, -------------------------------------------- 2000(A) 1999 1998 1997 1996 -------- -------- -------- -------- -------- Revenues (In Millions) Residential...................... $ 922.6 $ 975.2 $ 948.6 $ 932.5 $ 958.7 Commercial....................... 926.2 939.3 912.9 892.6 861.3 Industrial....................... 203.6 204.3 211.5 211.9 207.6 -------- -------- -------- -------- -------- System Sales.................... $2,052.4 $2,118.8 $2,073.0 $2,037.0 $2,027.6 ======== ======== ======== ======== ======== Sales (In Thousands)-- MWH: Residential...................... 11,675 11,349 10,965 10,806 11,243 Commercial....................... 14,042 13,565 13,219 12,718 12,591 Industrial....................... 4,476 4,350 4,583 4,575 4,596 -------- -------- -------- -------- -------- System Sales.................... 30,193 29,264 28,767 28,099 28,430 ======== ======== ======== ======== ======== Customers (In Thousands) Residential...................... 1,033.4 1,021.4 1,009.1 1,001.0 995.2 Commercial....................... 108.9 107.7 106.5 105.9 104.5 Industrial....................... 5.0 4.7 4.6 4.5 4.3 -------- -------- -------- -------- -------- Total........................... 1,147.3 1,133.8 1,120.2 1,111.4 1,104.0 ======== ======== ======== ======== ========
(A) Electric operating results reflect generation function as part of regulated operations through June 30, 2000. - -------------------------------------------------------------------------------- Gas Business Gas Regulatory Matters and 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. However, the delivery of gas continues to be regulated by the Maryland PSC. We buy all gas that we resell directly from various suppliers (rather than pipeline companies) and arrange separately for transportation and storage. Alternatively, we can transport gas for our customers. We also participate in the interstate markets, by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. We provide all of our customers with the option for delivery service across our distribution system so that they may make direct purchase and transportation arrangements with suppliers and pipelines. In addition to the delivery service, we also provide these customers with meter readings, billing, emergency response, regular maintenance, and balancing. Approximately 57% of the gas on our distribution system is for customers using delivery service. We charge all our delivery service customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales. Delivery service customers may choose to purchase gas from several different suppliers, including our subsidiary, BGE Home Products & Services, Inc. The basis of competition for delivery service customers is primarily commodity price. As part of our response to the increase in competition in the natural gas business, earnings from off-system gas sales and capacity release revenues are shared between shareholders and customers. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. We make these sales as part of a program to balance our supply of, and cost of, natural gas. In addition, we have a market based rates incentive mechanism for gas we sell on our system. 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. On November 17, 1999, BGE filed an application with the Maryland PSC to increase its gas base rates. The Maryland PSC authorized a $6.4 million annual increase in our gas base rates effective June 22, 2000. 12 Gas Operations We distribute natural gas purchased directly from many producers and marketers. We have transportation and storage agreements as shown below. These agreements are on file with the FERC. The gas is transported to our city gates, under various transportation agreements, by: . Columbia Gas Transmission Corporation, . Dominion Transmission Inc., and . Transcontinental Gas Pipe Line Corporation. To transport gas from the pipelines that supply gas to the pipelines that are connected to our city gates as mentioned above, we also have transportation capacity under contract with: . Texas Gas, . Columbia Gulf Transmission Company, and . ANR Pipeline Company. We have storage service agreements with: . Columbia Gas Transmission Corporation, . Dominion Transmission Inc., and . ANR Pipeline Company. Our current pipeline firm transportation entitlements to serve our firm loads are 284,053 DTH per day during the winter period and 259,053 DTH per day during the summer period. We use the firm transportation capacity to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas, and Canada to our city gates. We can arrange short-term contracts or exchange agreements with other gas companies in the event of short-term emergencies. We have three market area storage contracts to manage weather sensitive gas demand during the winter period. Our current maximum storage entitlements are 235,080 DTH per day. To supplement our gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, we have: . a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,000,000 DTH and a planned daily capacity of 287,988 DTH, and . a propane air facility with a mined cavern with a total storage capacity equivalent to 500,000 DTH and a planned daily capacity of 85,000 DTH. We have under contract sufficient volumes of propane for the operation of the propane air facility and are capable of liquefying sufficient volumes of natural gas during the summer months for operation of our liquefied natural gas facility during winter emergencies. 13 Gas Operating Statistics
Year Ended December 31, -------------------------------------------- 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- Gas Output (In Thousands) -- DTH: Purchased........................ 48,518 49,082 47,972 62,988 70,260 LNG Withdrawn from Storage....... 874 463 268 484 904 Produced......................... 261 486 46 541 784 -------- -------- -------- -------- -------- Total Output.................... 49,653 50,031 48,286 64,013 71,948 Delivery service gas (A)......... 67,658 59,494 55,608 52,629 45,964 Off-system sales (B)............. 22,456 15,543 16,724 14,759 9,968 -------- -------- -------- -------- -------- Total........................... 139,767 125,068 120,618 131,401 127,880 ======== ======== ======== ======== ======== Peak Day Sendout (DTH)............ 795,700 727,800 658,359 765,011 708,966 ======== ======== ======== ======== ======== Capability on Peak Day (DTH)...... 825,100 836,600 833,000 870,000 870,000 Revenues (In Millions) Residential Excluding Delivery Service...... $ 328.4 $ 298.1 $ 279.2 $ 321.7 $ 320.1 Delivery Service................ 23.5 11.5 4.9 0.5 -- Commercial Excluding Delivery Service...... 97.9 79.3 75.6 113.5 125.1 Delivery Service................ 25.8 24.4 19.4 12.9 7.2 Industrial Excluding Delivery Service...... 10.9 8.2 8.0 11.4 17.1 Delivery Service................ 16.3 16.1 16.0 17.2 14.6 -------- -------- -------- -------- -------- System sales..................... 502.8 437.6 403.1 477.2 484.1 Off-system sales................. 101.0 42.9 40.9 37.5 26.6 Other............................ 7.8 7.6 7.1 6.9 6.6 -------- -------- -------- -------- -------- Total........................... $ 611.6 $ 488.1 $ 451.1 $ 521.6 $ 517.3 ======== ======== ======== ======== ======== Sales (In Thousands) -- DTH: Residential Excluding Delivery Service...... 34,561 34,272 33,595 39,958 43,784 Delivery Service................ 9,209 4,468 1,890 205 -- Commercial Excluding Delivery Service...... 13,186 11,733 11,775 18,435 22,698 Delivery Service................ 22,921 20,288 16,633 12,964 8,755 Industrial Excluding Delivery Service...... 1,386 1,367 1,412 2,016 2,887 Delivery Service................ 32,382 33,118 34,798 38,791 36,201 -------- -------- -------- -------- -------- System sales..................... 113,645 105,246 100,103 112,369 114,325 Off-system sales................. 22,456 15,543 16,724 14,759 9,968 -------- -------- -------- -------- -------- Total........................... 136,101 120,789 116,827 127,128 124,293 ======== ======== ======== ======== ======== Customers (In Thousands) Residential...................... 553.7 543.5 532.5 524.5 516.5 Commercial....................... 40.1 39.9 39.6 39.3 38.9 Industrial....................... 1.4 1.3 1.3 1.3 1.3 -------- -------- -------- -------- -------- Total........................... 595.2 584.7 573.4 565.1 556.7 ======== ======== ======== ======== ========
For the periods presented, we achieved an all-time peak day sendout of 795,700 DTH on January 17, 2000. (A) Delivery service gas is gas purchased by customers directly from suppliers for which we receive a fee for transportation through our system. (B) Off-system sales are low-margin sales to wholesale suppliers of natural gas outside our service territory (beginning first quarter 1996). We discuss these programs further in the Gas Regulatory Matters and Competition section. 14 Franchises We have nonexclusive electric and gas franchises to use streets and other highways that are adequate and sufficient to permit us to engage in our present business. All such franchises, other than the gas franchises in Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and Frederick Counties, are unlimited as to time. The gas franchises for these jurisdictions expire at various times from 2015 to 2087, except for Havre de Grace which has the right, exercisable at twenty-year intervals from 1907, to purchase all of our gas properties in that municipality. Conditions of the franchises are satisfactory. - -------------------------------------------------------------------------------- Other Nonregulated Businesses International Projects At December 31, 2000, Constellation Power, Inc. had invested about $255.9 million in 10 power projects in Latin America. These investments include: . a 51% interest in a Panamanian electric distribution company by an investment group in which subsidiaries of Constellation Power hold an 80% interest, . existing electric generation facilities in Guatemala and Bolivia, and . an investment in an Energy Fund that has investments in Argentina, Brazil, and Bolivia. In December 1999, we decided to exit the Latin American portion of our business as a result of our concentration on domestic merchant energy. Currently, we are actively seeking a buyer for the Latin American portion of our business and are working toward completing our exit strategy in 2001. Energy Products and Services Constellation Energy Source, Inc. offers energy products and services designed primarily to provide solutions to the energy needs of commercial and industrial customers. These energy products and services include: . a full range of heating, ventilation, air conditioning, and energy services, . energy consulting and power-quality services, . services to enhance the reliability of individual electric supply systems, and . customized financing alternatives. Home Products, Commercial Building Systems, and Electric and Gas Retail Marketing BGE Home Products & Services, Inc. and subsidiaries offer services to residential, commercial, and industrial customers. These services include: . the sale and service of electric and gas appliances, . home improvements, . the sale and service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and . electric and natural gas retail marketing. ComfortLink ComfortLink provides cooling services using a central chilled water distribution system to commercial customers in Baltimore. Financial Investments Constellation Investments, Inc. engages in financial investments, including: . marketable securities, and . financial limited partnerships. Real Estate and Senior-Living Facilities Constellation Real Estate Group, Inc. develops, owns, and manages real estate and senior-living facilities, including: . land under development in the Baltimore-Washington corridor, . a mixed-use planned-unit development, . senior-living facilities, and . an equity interest in Corporate Office Properties Trust (COPT), a real estate investment trust. We describe the real estate business and the COPT transaction further in Item 7. Management's Discussion and Analysis and Note 3 to Consolidated Financial Statements. We consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate projects. If we were to decide to sell our real estate projects, we could have write-downs. In addition, if we were to sell our real estate projects in the current market, we would have losses, which could be material, although the amount of the losses is hard to predict. Depending on market conditions, we could also have material losses on any future sales. 15 Consolidated Capital Requirements Our business requires a great deal of capital. Our total capital requirements for 2000 were $1,877 million. Of this amount, $1,125 million was used in our nonregulated businesses and $752 million was used in our utility operations. We estimate our total capital requirements for the years 2001 through 2003 to be: . $2,529 million in 2001, . $1,863 million in 2002, and . $2,626 million in 2003. We continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimates for the years 2001 through 2003. We discuss our capital requirements further in Item 7. Management's Discussion and Analysis-- Capital Resources. - -------------------------------------------------------------------------------- Environmental Matters We are subject to regulation by various federal, state, and local authorities with regard to: . air quality, . water quality, . chemical and waste management and disposal, and . other environmental matters. Some of the regulations require substantial expenditures for additions to some of our older generating plants and the use of more low-sulfur fuels. We cannot precisely estimate the total effect on our facilities and operations of current and future environmental regulations and standards. However, our capital expenditures (excluding allowance for funds used during construction) were approximately $126 million during the five-year period 1996-2000 to comply with existing environmental standards and regulations, and we estimate that the future incremental capital expenditures (excluding allowance for funds used during construction) necessary to comply with existing environmental standards and regulations will be approximately: . $88 million in 2001, . $40 million in 2002, and . $7 million in 2003. Clean Air The Federal Clean Air Act regulates health and welfare standards for concentrations of air pollutants. Under this Act, each state must set limits on all major sources of these pollutants in its state so that the standards are not exceeded. We have certain emission or operational limits which include limits on sulfur content in fuel, releases of nitrogen oxides (NOx) emissions, release of particulate matter, facility design, or operational parameters imposed by either a federal or state agency on our generating units for the purpose of air quality control and compliance with existing air quality regulations. The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxides and NOx from certain electric generating stations--Title IV and Title I. Title IV addresses emissions of sulfur dioxides. For our older plants, we meet the requirements of Title IV through a combination of switching fuels and allowance trading. For newer plants, we meet the requirements of Title IV primarily through facility design, and operational and pollution controls. Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) has issued regulations, effective October 18, 1999, which required up to 65% NOx emissions reductions by May 1, 2000. We entered into a settlement agreement with the MDE since we could not meet this deadline. Under the terms of the settlement agreement, we will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that requires up to 85% NOx emissions reductions by 22 states (including Maryland and Pennsylvania). Maryland and Pennsylvania expect to meet the requirements of the rule by 2003. The emissions reduction equipment installations discussed above will allow us to meet these requirements in Maryland. The generating plants in Pennsylvania also will install emissions reduction equipment by 2003 to meet the 85% reduction requirements. We currently estimate that the additional controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately $150 million. Through December 31, 2000, we have spent approximately $115 million to meet the 65% reduction requirements. We estimate the additional cost for the EPA's 85% reduction requirements to be approximately $90 million by 2003. These amounts will be paid by our domestic merchant energy business. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. In 1999, these new standards were successfully challenged in court. The EPA appealed 16 the 1999 court rulings to the Supreme Court. In February 2001, the Supreme Court upheld EPA's authority to issue the standards. However, the Supreme Court sent the case back to the lower court and EPA for further proceedings on implementation issues related to the revised ozone standard. The lower court will also address remaining challenges to the fine particulate standard. While these standards may require increased controls at the fossil generating plants in the future, implementation, if required, would 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. In December 2000, the EPA issued a determination that coal-fired power plant mercury emissions will be controlled. Final regulations are expected to be issued in 2004 with controls required by 2007. The costs of these controls cannot be estimated at this time since the level of control or systems to implement them have not yet been established. We received letters from the EPA requesting us to provide certain information under Section 114 of the federal Clean Air Act regarding some of our electric generating plants. 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. We have provided the EPA the requested information. We believe our generating plants have been operated in accordance with the Clean Air Act and the rules implementing the Clean Air Act. However, we cannot estimate the impact of this inquiry on our generating plants, and our financial results, at this time. Water Each state regulates the discharge of process wastewater and certain stormwater discharges into its waters under the National Pollutant Discharge Elimination System permit program. This program was established as part of the Federal Clean Water Act. At the present time, we have the required permits under the program for all of our electric generating plants. The water quality regulations require us to, among other things, define procedures to determine compliance with each state's water quality standards. These procedures require extensive studies involving sampling and monitoring of the waters around affected generating plants. Each state may require changes in plant operations. We continually perform studies to determine whether any changes will be necessary to comply with these regulations. Waste Disposal The EPA has regulations for implementing the portions of the Resource Conservation and Recovery Act that deal with the management of hazardous wastes. These regulations, and the Hazardous and Solid Waste Amendments of 1984, identify certain spent materials as hazardous wastes and establish standards and requirements for those who generate, transport, store, or dispose of such wastes. States have adopted regulations governing the management of hazardous wastes that are similar to the EPA regulations and in some cases more stringent. We have procedures in place to comply with all applicable EPA and state regulations governing the management of hazardous wastes. Some high volume utility wastes, such as coal fly ash and bottom ash, are exempt from these regulations. We currently use all of our coal fly ash and bottom ash in a manner consistent with federal, state, and local laws and regulations. These include the use of ash as structural fill material, and recycled material that can be sold to the construction industry for a number of other approved uses. We also deposit ash in landfills. We continue to evaluate various recycling opportunities for our coal fly ash and bottom ash. The Federal Comprehensive Environmental Response, Compensation and Liability Act (Superfund statute) establishes liability for the cleanup of hazardous wastes that contaminate the soil, water, or air. Those who generated, transported, or deposited the waste at the contaminated site are each jointly and severally liable for the cost of the cleanup, as are the current property owner and the owner when the contamination occurred. Many states have implemented laws similar to the Superfund statute. 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. In the early 1970s, we shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has been found to be contaminated with oil containing high levels of PCBs (hazardous chemicals frequently used as a fire-resistant coolant in electrical equipment). On December 7, 1987, the EPA notified us and nine other utilities that we are considered potentially responsible parties (PRPs) with respect to the cleanup of the site. We, along with the other PRPs, 17 submitted a remedial investigation and feasibility study (RI/FS) to the EPA on October 14, 1994, and the EPA issued its Record of Decision (ROD) on December 31, 1997. On June 26, 1998, the EPA ordered us, the other utility PRPs, and the owner/operator to implement the requirements of the ROD. The utility PRPs are currently conducting the remedial design. Based on the ROD, our share of the reasonably possible cleanup costs, estimated to be approximately 15.47%, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. On October 16, 1989, the EPA filed a complaint in the U.S. District Court for the District of Maryland under the Superfund statute against us and seven other defendants to recover past and future expenditures associated with the cleanup of a site located at Kane and Lombard Streets in Baltimore. The State of Maryland filed a similar complaint in the same case and court on February 12, 1990. The complaints alleged that we arranged for our coal fly ash to be deposited on the site. The Court dismissed these complaints in November 1995. The MDE began additional investigation on the remainder of the site for the EPA, but never completed the investigation. We, along with three other defendants, agreed to complete the RI/FS of groundwater contamination around the site in a July 1993 consent order. The remedial action, if any, for the remainder of the site will not be selected until these investigations are concluded. Therefore, we cannot estimate the total amount, or our share, of the site cleanup costs. From 1985 until 1989, we shipped waste oil and other materials to the Industrial Solvents and Chemical Company in York County, Pennsylvania for disposal. The Pennsylvania Department of Environmental Protection (PADEP) subsequently investigated this site and found it to be heavily contaminated by hazardous wastes. The PADEP notified us on August 15, 1990, that approximately 1,000 other entities and we are PRPs with respect to the cost of all remedial activities to be conducted at the site. The PRPs have performed waste characterization, removed and disposed of all tanks and drums of waste, completed a RI/FS at the site, and installed public water lines. In 1998, PADEP notified BGE and other PRPs of the final remedy and requested the installation of additional public water lines. In 1999, the PRPs installed the water lines and PADEP approved the final report in March 2000. We have no further obligations under the consent orders at the site. In December 1995, the EPA notified us that we are one of approximately 650 parties that may have incurred liability under the Superfund statute for shipments of hazardous wastes to a site in Denver, Colorado known as the RAMP Industries site. We, through our disposal vendor, shipped a small amount of low level radioactive waste to the site between 1989 and 1992. The site, which was found to have been operated improperly, was closed in 1994. That same year, the EPA began cleaning up the site by removing drums of radioactive and hazardous mixed wastes. BGE accepted a settlement offer from EPA in August 1999, whereby BGE will pay an immaterial amount to resolve its liability at this site. The consent order will be finalized in 2001. In September 1996, we received an information request from the EPA about the Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site was the subject of an emergency drum removal action in 1991, due to a concern about hazardous substances leaking from drums and posing a threat to human health and the environment. According to EPA documents, approximately $2 million was spent on the drum removal action. To our knowledge, no long-term remediation is planned for this site. In addition, we understand that the EPA has sent information requests to approximately 17 other parties. Our records indicate that we sold empty drums to Drumco, Inc. from approximately 1983-1990. Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we sold only empty storage drums to Drumco, Inc. On July 12, 1999, the EPA notified us, along with 19 other entities, that we may be a potentially responsible party at the 68th Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump, located in Baltimore, Maryland. The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized. Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we did not send waste to the site. In the early part of the century, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The residue from this manufacturing process was coal tar, previously thought to be harmless but now found to contain a number of chemicals designated by the EPA as hazardous substances. We are coordinating an investigation of some of these former manufacturing sites, and determining what, if any, remedial action may be required by MDE. In late December 1996, we signed a consent order with the MDE that requires us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, 18 Maryland. We submitted the required remedial action plans and they have been approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million in nominal dollars (including inflation). We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. We discuss this further in Note 5 to Consolidated Financial Statements. Through December 31, 2000, we have spent approximately $35 million for remediation at this site. We are also required by accounting rules to disclose additional costs we consider to be less likely than probable, but still "reasonably possible" of being incurred at these sites. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million in nominal dollars ($7 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 36 years). Employees As of December 31, 2000, we employed about 7,800 people. - -------------------------------------------------------------------------------- Item 2. Properties We lease several properties that are used for Constellation Energy's headquarters, various offices, and services. We own BGE's principal headquarters building in downtown Baltimore. We describe our electric generation properties in the Domestic Merchant Energy Business section. We own the following propane air and liquefied natural gas facilities: . a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,000,000 DTH and a planned daily capacity of 287,988 DTH, and . a propane air facility with a mined cavern with a total storage capacity of 500,000 DTH and a planned daily capacity of 85,000 DTH. We also have rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City owned property (principally parks) which expire in 2004. These rights-of-way can be renewed during their last year for an additional period of 25 years based on a fair revaluation. Conditions of the grants are satisfactory. property. All of BGE's property and the electric generation assets that were transferred by BGE to our domestic merchant energy business as part of deregulation, are subject to the lien of BGE's mortgage securing its mortgage bonds. - -------------------------------------------------------------------------------- Item 3. Legal Proceedings In the normal course of business, we are involved in various legal proceedings. We discuss our legal proceedings in Note 10 to Consolidated Financial Statements. 19 Item 4. Submission of Matters to Vote of Security Holders Not applicable. Executive Officers of the Registrant BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, the executive officers of BGE are not presented below. Executive Officers of Constellation Energy Group at the date of this report are:
Other Offices or Positions Name Age Present Office Held During Past Five Years ---- --- -------------- --------------------------- Christian H. Poindexter 62 Chairman of the Board and Chief Chairman of the Board, Executive Officer (A) (Since President, and Chief formation of Constellation Executive Officer-- Energy Group as the holding Constellation Energy and company on April 30, 1999; since BGE March 1, 1998 for BGE) Edward A. Crooke 62 Vice Chairman (B) (Since October Vice Chairman--Constellation 20, 2000) Energy, Chairman of the Board, President and Chief Executive Officer-- Constellation Enterprises, Inc., Chairman of the Board--Constellation Holdings, Inc., and President and Chief Operating Officer--BGE Eric P. Grubman 43 Co-President (Since October 20, Partner and Managing 2000) Director, Co-Head of Energy & Power--Goldman Sachs & Co. Charles W. Shivery 55 Co-President (Since October 20, Chairman of the Board and 2000) Chief Executive Officer-- President and Chief Executive Constellation Energy Officer, Constellation Power Source, Inc., Vice Source Holdings, Inc. (since President, Chief Financial July 1, 2000), Officer & Secretary--BGE CEO and President, Constellation Enterprises, Inc. (since 1998), Chairman of the Board, President, and Chief Executive Officer, Constellation Power Source, Inc. (since 1997) Robert E. Denton 58 President and Chief Executive Executive Vice President, Officer of Constellation Generation--BGE, Senior Nuclear, LLC (since July 1, 2000) Vice President, Generation--BGE Frank O. Heintz 57 President and Chief Executive Executive Vice President, Officer of Baltimore Gas and Utility Operations--BGE, Electric Company (since July 1, Vice President, Gas--BGE. 2000) Thomas F. Brady 51 Vice President Corporate Strategy Vice President, Retail and Development (Since formation Services--BGE, Vice of Constellation Energy Group as President, Customer Service the holding company on April 30, and Distribution--BGE 1999; since January 1, 1999 for BGE) David A. Brune 60 Vice President Finance and General Counsel--BGE Accounting, Chief Financial Officer and Secretary (Since formation of Constellation Energy Group as the holding company on April 30, 1999; since February 25, 1997 for BGE)
20
Other Offices or Positions Name Age Present Office Held During Past Five Years ---- --- -------------- --------------------------- Robert S. Fleishman 47 Vice President Corporate Affairs General Counsel--BGE, and General Counsel (Since Associate General Counsel-- formation of Constellation Regulatory at BGE Energy Group as the holding company on April 30, 1999; since May 1, 1998 for BGE) Janet E. McHugh 43 Vice President Human Resources Deputy General Counsel and (Since June 1, 2000) Manager, Legal Department-- Constellation Energy, Associate General Counsel-- Commercial Unit--BGE
(A) Chief Executive Officer, Director, and member of the Executive Committee. (B) Director and member of the Executive Committee, Long-Range Strategy Committee, and Risk Management Committee. Officers of Constellation Energy Group are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected. - -------------------------------------------------------------------------------- PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters Stock Trading Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York, Chicago, and Pacific stock exchanges. It has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges. As of February 28, 2001, there were 58,650 common shareholders of record. Dividend Policy Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There is no limitation on Constellation Energy paying common stock dividends. BGE pays dividends on its common stock after its Board of Directors declares them. There is no limitation on BGE paying common stock dividends unless: . BGE elects to defer interest payments on the 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038, and any deferred interest remains unpaid; or . all dividends (and any redemption payments) due on BGE's preference stock have not been paid. Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, our financial condition, and other factors. Effective April 2001, our annual dividend is expected to be set at $.48 per share ($.12 quarterly). Upon separation, BGE Corp. expects to pay initial annual dividends of $.48 per share, and Constellation Energy Group, as a growing merchant energy company, initially expects to reinvest its earnings in order to fund its growth plans and not to pay a dividend. Quarterly dividends were declared on the common stock during 2000 and 1999 in the amounts set forth below. Dividends paid prior to April 30, 1999 were on BGE common stock. As a result of the share exchange, Constellation Energy is the successor of BGE. - -------------------------------------------------------------------------------- Common Stock Dividends and Price Ranges
2000 1999 ---------------------- ---------------------- Price* Price* Dividend ------------- Dividend ------------- Declared High Low Declared High Low -------- ------ ------ -------- ------ ------ First Quarter..................... $ .42 $33.81 $27.06 $ .42 $31.13 $24.69 Second Quarter.................... .42 35.69 31.25 .42 31.38 25.13 Third Quarter..................... .42 52.06 32.06 .42 30.88 27.19 Fourth Quarter.................... .42 50.50 37.88 .42 31.50 27.50 ----- ----- Total............................. $1.68 $1.68 ===== =====
* Based on New York Stock Exchange Composite Transactions as reported in THE WALL STREET JOURNAL. 21 Item 6. SELECTED FINANCIAL DATA Constellation Energy Group Inc., and Subsidiaries
2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, except per share amounts) Summary of Operations Total Revenues $ 3,878.5 $3,786.2 $3,386.4 $3,307.6 $3,153.2 Total Expenses 3,038.3 3,026.3 2,647.9 2,584.0 2,483.7 - ---------------------------------------------------------------------------------------------------------------------------- Income From Operations 840.2 759.9 738.5 723.6 669.5 Other Income (Expense) 6.6 7.9 5.7 (52.8) 6.1 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 846.8 767.8 744.2 670.8 675.6 Fixed Charges 271.4 255.0 260.6 258.7 237.0 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 575.4 512.8 483.6 412.1 438.6 Income Taxes 230.1 186.4 177.7 158.0 166.3 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 345.3 326.4 305.9 254.1 272.3 Extraordinary Loss, Net of Income Taxes -- (66.3) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------- Net Income $ 345.3 $ 260.1 $ 305.9 $ 254.1 $ 272.3 ============================================================================================================================ Earnings Per Share of Common Stock and Earnings Per Share of Common Stock-- Assuming Dilution Before Extraordinary Item $ 2.30 $ 2.18 $ 2.06 $ 1.72 $ 1.85 Extraordinary Loss, Net of Income Taxes -- (.44) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------- Earnings Per Share of Common Stock and Earnings Per Share of Common Stock-- Assuming Dilution $ 2.30 $ 1.74 $ 2.06 $ 1.72 $ 1.85 ============================================================================================================================ Dividends Declared Per Share of Common Stock $ 1.68 $ 1.68 $ 1.67 $ 1.63 $ 1.59 ============================================================================================================================ Summary of Financial Condition Total Assets $12,384.6 $9,683.8 $9,434.1 $8,900.0 $8,678.2 ============================================================================================================================ Capitalization Long-term debt $ 3,159.3 $2,575.4 $3,128.1 $2,988.9 $2,758.8 Redeemable preference stock -- -- -- 90.0 134.5 Preference stock not subject to mandatory redemption 190.0 190.0 190.0 210.0 210.0 Common shareholders' equity 3,153.0 2,993.0 2,981.5 2,870.4 2,854.7 - ---------------------------------------------------------------------------------------------------------------------------- Total Capitalization $ 6,502.3 $5,758.4 $6,299.6 $6,159.3 $5,958.0 ============================================================================================================================ Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.78 2.87 2.60 2.35 2.44 Book Value Per Share of Common Stock $ 20.95 $ 20.01 $ 19.98 $ 19.44 $ 19.33 Number of Common Shareholders (In Thousands) 60.1 66.1 69.9 73.7 77.6
Certain prior-year amounts have been reclassified to conform with the current year's presentation. 22 Baltimore Gas and Electric Company and Subsidiaries
2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, except per share amounts) Summary of Operations Total Revenues $ 2,746.8 $3,092.2 $3,386.4 $3,307.6 $3,153.2 Total Expenses 2,336.7 2,387.9 2,647.9 2,584.0 2,483.7 - ---------------------------------------------------------------------------------------------------------------------------- Income From Operations 410.1 704.3 738.5 723.6 669.5 Other Income (Expense) 9.8 8.4 5.7 (52.8) 6.1 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 419.9 712.7 744.2 670.8 675.6 Fixed Charges 184.0 205.9 238.8 230.0 198.5 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 235.9 506.8 505.4 440.8 477.1 Income Taxes 92.4 178.4 177.7 158.0 166.3 - ---------------------------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 143.5 328.4 327.7 282.8 310.8 Extraordinary Loss, Net of Income Taxes -- (66.3) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------- Net Income 143.5 262.1 327.7 282.8 310.8 Preference Stock Dividends 13.2 13.5 21.8 28.7 38.5 - ---------------------------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 130.3 $ 248.6 $ 305.9 $ 254.1 $ 272.3 ============================================================================================================================ Summary of Financial Condition Total Assets $ 4,654.2 $7,272.6 $9,434.1 $8,900.0 $8,678.2 ============================================================================================================================ Capitalization Long-term debt $ 1,864.4 $2,206.0 $3,128.1 $2,988.9 $2,758.8 Redeemable preference stock -- -- -- 90.0 134.5 Preference stock not subject to mandatory redemption 190.0 190.0 190.0 210.0 210.0 Common shareholders' equity 802.3 2,355.4 2,981.5 2,870.4 2,854.7 - ---------------------------------------------------------------------------------------------------------------------------- Total Capitalization $ 2,856.7 $4,751.4 $6,299.6 $6,159.3 $5,958.0 ============================================================================================================================ Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.27 3.45 2.94 2.78 3.10 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Stock Dividends 2.03 3.14 2.60 2.35 2.44
Certain prior-year amounts have been reclassified to conform with the current year's presentation. 23 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE(R)) and Constellation(R) Enterprises, Inc. Constellation Enterprises was previously owned by BGE. This report 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. Reference in this report to the "utility business" is to BGE. Constellation Energy's subsidiaries primarily include a domestic merchant energy business focused mostly on power marketing and merchant generation in North America, and BGE. We realigned our organization in response to the deregulation of electric generation in Maryland. In the first quarter of 2000, we combined our wholesale power marketing operation with our domestic plant development and operation activities to form a domestic merchant energy business. At the same time, we revised our operating segments to reflect those realignments as presented in Note 2. On July 1, 2000, as a result of the deregulation of electric generation, BGE transferred its generating assets and related liabilities at book value to new nonregulated subsidiaries -- Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation, Inc. We discuss the deregulation of electric generation in the Current Issues--Electric Competition section. Effective July 1, 2000, we formed a nonregulated holding company, Constellation Power Source Holdings, Inc., that oversees: . the wholesale power marketing and risk management activities of Constellation Power Source,(TM) Inc., . the domestic power projects of Constellation Investments,(TM) Inc. and Constellation Power,(TM) Inc., and subsidiaries, and . the generating assets of Constellation Power Source Generation, Inc. As a result of these changes, our domestic merchant energy business includes the operations of Constellation Power Source Holdings, the nuclear generation of Calvert Cliffs Nuclear Power Plant, Inc., and the nuclear consulting services of Constellation Nuclear,(TM) LLC. Also, effective July 1, 2000, the financial results of the electric generation portion of our business are included in the domestic merchant energy business. Prior to that date, the financial results of electric generation were included in BGE's regulated electric business. BGE remains a regulated electric and gas public utility distribution company with a service territory in the City of Baltimore and all or part of ten counties in Central Maryland. Our other nonregulated businesses include the: . Latin American power projects of Constellation Power, and subsidiaries, . energy products and services of Constellation Energy Source,(TM) Inc., . home products, commercial building systems, and residential and commercial electric and gas retail marketing of BGE Home Products & Services,(TM) Inc. and subsidiaries, . general partnership, in which BGE is a partner, of District Chilled Water General Partnership (ComfortLink(R)) that provides cooling services for commercial customers in Baltimore, . financial investments of Constellation Investments, and . real estate holdings and senior-living facilities of Constellation Real Estate Group,(TM) Inc. As discussed further in the Strategy section, on October 23, 2000, we announced initiatives to separate our domestic merchant energy business from our remaining businesses. These remaining businesses include BGE and the other nonregulated businesses described above. In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including: . what factors affect our businesses, . what our earnings and costs were in 2000 and 1999, . why our earnings and costs changed from the year before, . where our earnings come from, . how all of this affects our overall financial condition, . what our expenditures for capital projects were for 1998 through 2000, and what we expect them to be through 2003, and . where we expect to get cash for future capital expenditures. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2000, 1999, and 1998. We analyze and explain the differences between periods by operating segment. Our analysis is important in making decisions about your investments in Constellation Energy and/or BGE. Also, this discussion and analysis is based on the operation of the electric generation portion of our utility business under rate regulation through June 30, 2000. Our regulated electric business changed as we transferred our electric generation assets and related liabilities to our domestic merchant energy business and we entered into retail customer choice for electric generation effective July 1, 2000. In addition, we announced our intention to separate our domestic merchant energy business from our remaining businesses. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance. 24 STRATEGY Customer choice and regulatory change significantly impact our business. In response to these, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going forward, prior to separating into two companies, we expect to derive almost two- thirds of our earnings from our domestic merchant energy business. While BGE continues to be regulated and to deliver electricity and natural gas through its core distribution business, our primary growth strategies center on the nonregulated domestic merchant energy business with the objective of providing new sources of earnings growth. On October 23, 2000, we announced three initiatives to advance our growth strategies. The first initiative is that we entered into an agreement (the "Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a 17.5% equity interest in our domestic merchant energy business, which will be consolidated under a single holding company ("Holdco"). Goldman Sachs will also acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to certain adjustments). The warrant is exercisable six months after Holdco's common stock becomes publicly available. The amount of common stock which Goldman Sachs may receive upon exercise will be equal to the excess of the market price of Holdco's common stock at the time of exercise over the exercise price of $60 per share for all the stock subject to the warrant, divided by the market price. Holdco may at its option pay Goldman Sachs such excess in cash. Goldman Sachs is acquiring its interest and the warrant in exchange for $250 million in cash (subject to adjustment in certain instances) and certain assets related to our power marketing operation. At closing, Goldman Sachs' existing services agreement with our power marketing operation will terminate. The second initiative is a plan to separate our domestic merchant energy business from our remaining businesses as discussed in the introduction. The separation will create two stand-alone, publicly traded energy companies. One will be a merchant energy business engaged in wholesale power marketing and generation under the name "Constellation Energy Group" after the separation. The other will be a regional retail energy delivery and energy services company, BGE Corp., which will include BGE, our other nonregulated businesses, and our investment in Orion Power Holdings, Inc. ("Orion"). As a result of the separation, shareholders will continue to own all of Constellation Energy's current businesses through their ownership of the stock of the new Constellation Energy Group and of BGE Corp. The third initiative is a change in our common stock dividend policy effective April 2001. In a move closely aligned with our separation plan, effective April 2001, our annual dividend is expected to be set at $.48 per share. After the separation, BGE Corp. expects to pay initial annual dividends of $.48 per share. Constellation Energy Group, as a growing merchant energy company, initially expects to reinvest its earnings in order to fund its growth plans and not to pay a dividend. The closing of the transaction with Goldman Sachs and the separation are subject to customary closing conditions and contingent upon obtaining regulatory approvals and a Private Letter Ruling from the Internal Revenue Service regarding certain tax matters. The transaction and separation are expected to be completed by mid to late 2001. At the date of this report, we received approval from the Federal Energy Regulatory Commission (FERC). We discuss these strategic initiatives further in our Report on Form 8-K and exhibits filed with the Securities and Exchange Commission (SEC)on October 23, 2000. Currently, our domestic merchant energy business controls over 9,000 megawatts of generation. In December 2000, we announced that a subsidiary of Constellation Nuclear will purchase 1,550 megawatts of the 1,757 megawatts total generating capacity of the Nine Mile Point nuclear power plant located in Scriba, New York. The total purchase price, including fuel, is $815 million. We discuss the planned acquisition of the Nine Mile Point power plant in more detail in Note 10. We also are constructing generating facilities representing 1,100 megawatts of natural gas-fired peaking capacity in the Mid-Atlantic and Mid-West regions which are expected to be operational by the summer of 2001. An additional 6,700 megawatts of natural gas-fired peaking and combined cycle production facilities in various regions of North America are scheduled for completion in 2002 and beyond. By 2005, our domestic merchant energy business expects to control approximately 30,000 megawatts through the construction or purchase of additional nuclear and non-nuclear generation assets and through contractual arrangements. We decided to exit the Latin American portion of our operation as a result of our concentration on domestic merchant energy. Currently, we are actively seeking a buyer for the Latin American portion of our business and are working toward completing our exit strategy in 2001. We also might consider one or more of the following strategies: . the complete or partial separation of our transmission and distribution functions, . mergers or acquisitions of utility or non-utility businesses, and . sale of generation assets or one or more businesses. 25 CURRENT ISSUES With the shift toward customer choice, competition, and the growth of our domestic merchant energy business, various factors will affect our financial results in the future. These factors include, but are not limited to, operating our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause, the timing and implications of deregulation in other regions where our domestic merchant energy business will operate, the loss of revenues due to customers choosing alternative suppliers, higher volatility of earnings and cash flows, and increased financial requirements of our domestic merchant energy business. Please refer to the Forward Looking Statements section for additional factors. In this section, we discuss in more detail several issues that affect our businesses. Electric Competition - -------------------- We are facing electric competition on various fronts, including: . the construction of generating units to meet increased demand for electricity, . the sale of electricity in wholesale power markets, . competing with alternative energy suppliers, and . electric sales to retail customers. Maryland - -------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland Public Service Commission (Maryland PSC) addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 4. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are discussed in Note 4. We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises-- Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated. We describe the effect of applying these accounting requirements in Note 4. Please refer to Note 10 for a discussion regarding appeals of the Restructuring Order. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000: . All customers, except a few commercial and industrial companies that have signed contracts with BGE, can choose their electric energy supplier. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. . BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year. These rates will not change before July 2006. . BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. In total, these generating assets represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion. . BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power Plant, Inc. and $231 million to Constellation Power Source Generation of tax-exempt debt related to the transferred assets. Also, Constellation Power Source Generation issued approximately $366 million in unsecured promissory notes to BGE. Repayments of the notes by Constellation Power Source Generation will be used exclusively to service the current maturities of certain BGE long-term debt. . BGE transferred equity associated with the generating assets to Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation. . The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE were also assumed by these subsidiaries. 26 Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period for those customers that do not choose an alternate supplier. In addition, the electric fuel rate was discontinued effective July 1, 2000. Constellation Power Source provides BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Thereafter, BGE will competitively bid the energy and capacity. 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 - ------------ Our domestic merchant energy business is focused on expanding its business through marketing energy products to wholesale customers and acquiring control of additional generating facilities. This business will focus on states with strong growth in energy demand and that provide opportunities through ongoing deregulation and the creation of competitive markets. Delays in, or the ultimate form of, deregulation of electric generation in various states may affect our domestic merchant energy business strategy. Our domestic merchant energy business has $297.9 million invested in power projects that sell 142 megawatts of electricity in California under power purchase agreements as discussed in the California Power Purchase Agreements section. The counterparties to the agreements are two California investor-owned utilities. Due to various factors, including shortage of generation and the high cost of natural gas, these utilities' financial condition was severely impacted because they were paying more for power than they were allowed to recover from their customers under the deregulation plan in California. As a result, these utilities have not been able to maintain current payments for the power they purchased to meet their customers' energy needs and the credit ratings of these utilities were downgraded below investment grade. The governor and legislature of California have undertaken emergency actions to stabilize the financial condition of the two utilities by purchasing power on behalf of these utilities and pursuing legislation that should permit the utilities to pay their power costs. In the meantime, these utilities have not been paying our California projects in full for power supplied to them from December 2000. As of the date of this report, our portion of the amount due from these utilities is approximately $42 million. While we expect to be paid for this power, we cannot predict when payment will occur or if full payment will be received. We have taken reserves in amounts we believe to be reasonable under the circumstances. On March 27, 2001, the California Public Utilities Commission issued an order for an immediate retail rate increase. Accordingly, we expect that this order should enable these utilities to pay us for all future power supplied to these utilities. However, if the ultimate resolution of the events in California prevents collection of unpaid balances under power purchase agreements by some or all of our projects, it could have a material impact on our financial results. Additionally, if the events in California result in a modification or termination of these agreements that reduces future cash flows, we would have to evaluate whether our investments in the power projects that are parties to the agreements are impaired. An impairment of these investments could have a material impact on our financial results. Our domestic merchant energy business does not have any other direct agreements with these utilities. However, we may be impacted if one or more of our other counterparties is significantly affected by the events in California, or by the operation of the California Power Exchange. 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. Under traditional rate regulation that continues after July 1, 2000 for BGE's electric transmission and distribution, and gas businesses, the Maryland PSC determines the rates we can charge our customers. Prior to July 1, 2000, BGE's regulated electric rates consisted primarily of a "base rate" and a "fuel rate." Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled its 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 fixed asset 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. 27 On November 17, 1999, BGE filed an application with the Maryland PSC to increase its gas base rates. On June 19, 2000, the Maryland PSC authorized a $6.4 million annual increase in our gas base rates effective June 22, 2000. As a result of the Restructuring Order, BGE's residential electric base rates are frozen until 2006. Electric delivery service rates are frozen for a four-year period 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 - --------- Through June 30, 2000, we charged our electric customers separately for the fuel we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity. We charged the actual cost of these items to the customer with no profit to us. If these fuel costs went up, the Maryland PSC permitted us to increase the fuel rate. Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1, 2000, at which time the fuel rate clause was discontinued. We deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. Effective July 1, 2000, our earnings are affected by the changes in the cost of fuel and energy. We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market based rates incentive mechanism approved by the Maryland PSC. We discuss market based rates in more detail in the Gas Cost Adjustments section and in Note 1. 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). The regulations require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in a RTO. FERC also identified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered a RTO. According to Order 2000, a public utility that is a member of an existing transmission entity that has been approved by FERC as in conformance with the Independent System Operator (ISO) principles set forth in the FERC Order No. 888, such as BGE, through its membership in PJM (Pennsylvania-New Jersey- Maryland) Interconnection, was required to make a filing no later than January 15, 2001. PJM and the joint transmission owners, including BGE, made the filing on October 11, 2000. That filing explained the extent to which PJM met the minimum characteristics and functions of a RTO and explained its plans to conform to these characteristics and functions. As a member of PJM, an existing ISO, BGE does not expect to be materially impacted by Order 2000. However, we are appealing two requirements of Order 2000 whereby: . we would have to go through PJM to make a filing with FERC to change our transmission rates, and . we would have to transfer operational control of our transmission facilities to PJM. The U.S. Supreme Court agreed to hear an appeal by others of FERC Order 888. We cannot predict the outcome of this appeal or the impact on BGE at this time. Weather - ------- Domestic Merchant Energy Business - --------------------------------- Weather conditions in the different regions of North America influence the financial results of our domestic merchant energy business. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. However, all regions of North America typically do not experience extreme weather conditions at the same time. Since the majority of our generating plants currently are located in PJM, our financial results are affected, to a greater extent, by weather conditions in this area. However, by 2005, we expect to control approximately 30,000 megawatts of generation throughout various regions of North America. Current weather conditions also can affect the forward market price of energy commodity and derivative contracts used by our power marketing operation that are accounted for on a mark-to-market basis. To the extent that our power marketing operation purchases and sells such contracts, our financial results could be influenced by the impact that weather conditions have on the market price of such contracts. 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. We measure the weather's effect using "degree days." A degree day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. 28 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 cooling and heating degree days in 2000 and 1999, the percentage change in the number of degree days from the prior year, and the number of degree days in a "normal" year as represented by the 30-year average in the following table. 30-year 2000 1999 Average - -------------------------------------------------------- Cooling degree days 736 845 840 Percentage change from prior year (12.9)% (7.7)% Heating degree days 4,936 4,585 4,771 Percentage change from prior year 7.7% 11.3% Other Factors - ------------- Other factors, aside from weather, impact the demand for electricity and gas in our regulated businesses. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of regulated electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during the periods presented. The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory. Under the Restructuring Order, BGE's electric customers can become delivery service customers only and can purchase their electricity from other sources. We will collect a delivery service charge to recover the fixed costs for the service we provide. The remaining electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas. Environmental and Legal Matters - ------------------------------- You will find details of our environmental and legal matters in Note 10. You will find additional details of our environmental matters under Item 1. Business -- Environmental Matters. Some of the information is about costs that may be material to our financial results. Accounting Standards Issued - --------------------------- We discuss recently issued accounting standards in Note 1. RESULTS OF OPERATIONS 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. Overview - -------- Total Earnings Per Share of Common Stock 2000* 1999 1998 - ------------------------------------------------------------------------ Earnings before nonrecurring charges included in operations: Domestic merchant energy $1.48 $ .44 $ .36 Regulated electric .71 1.81 1.75 Regulated gas .20 .22 .18 Other nonregulated .04 .01 (.09) - ------------------------------------------------------------------------ Total earnings per share before nonrecurring charges included in operations: 2.43 2.48 2.20 Nonrecurring charges included in operations (see Note 2): Deregulation transition cost (.10) -- -- TVSERP (.03) -- -- Hurricane Floyd -- (.03) -- Write-downs of power projects -- (.12) -- Write-off of energy services investment -- -- (.04) Write-down of financial investment -- (.11) -- Write-down of real estate and senior-living investments -- (.04) (.10) - ------------------------------------------------------------------------ Total earnings per share before extraordinary item 2.30 2.18 2.06 Extraordinary loss (see Note 4) -- (.44) -- - ------------------------------------------------------------------------ Total earnings per share $2.30 $1.74 $2.06 ======================================================================== *Earnings for the years presented reflect a significant shift from the regulated electric business to the domestic merchant energy business as a result of the transfer of BGE's electric generation assets to nonregulated subsidiaries on July 1, 2000 in accordance with the Restructuring Order. We discuss the Restructuring Order in more detail in Note 4. 29 2000 - ---- Our 2000 total earnings increased $85.2 million, or $.56 per share, compared to 1999 mostly because we recorded an extraordinary charge of $66.3 million, or $.44 per share, associated with the deregulation of the electric generation portion of our business in 1999. In addition, we recorded several nonrecurring charges in 1999 that had a negative impact in that year as discussed below. In 2000, we recorded the following nonrecurring charges in operations: . $15.0 million after-tax, or $.10 per share, deregulation transition cost in June 2000 to a third party incurred by our power marketing operation to provide BGE's standard offer service requirements, and . $4.2 million after-tax, or $.03 per share, expense during the first and second quarters of 2000 for BGE employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP). Earnings before nonrecurring charges included in operations decreased $7.3 million, or $.05 per share, mostly because we recognized $29.9 million, or $18.1 million after-tax, of the 6.5% annual residential rate reduction that was effective July 1, 2000 and we had higher interest costs in 2000 compared to 1999. We also recognized $5.7 million after-tax, or $.04 per share, for contributions to the universal service fund relating to the deregulation of electric generation. These decreases were offset partially by higher earnings in our domestic merchant energy and our other nonregulated businesses. In 2000, earnings from our domestic merchant energy business before nonrecurring charges increased compared to 1999 because of higher earnings in both our power marketing and domestic generation operations. In 2000, earnings from our other nonregulated businesses increased mostly because of higher earnings in our financial investments operation. 1999 - ---- Our 1999 total earnings decreased $45.8 million, or $.32 per share, compared to 1998. Our total earnings decreased mostly because we recorded an extraordinary charge associated with the deregulation of the electric generation portion of our business. We discuss the extraordinary charge in Note 4. Our 1999 total earnings also include the following nonrecurring items included in our operations: . Our regulated electric business recorded $4.9 million after-tax, or $.03 per share, of expenses related to Hurricane Floyd. . Our domestic generation operation recorded write-downs of certain power projects for $14.2 million after-tax, or $.09 per share, and our Latin American operation recorded a $4.5 million after-tax, or $.03 per share, write-down of a power project. . Our financial investments operation recorded a $16.0 million after-tax, or $.11 per share, write-down of a financial investment. . Our real estate and senior-living facilities operation recorded a $5.8 million after-tax, or $.04 per share, write-down of certain senior-living facilities. These decreases were offset partially by higher earnings from regulated utility, domestic merchant energy, and other nonregulated business operations excluding nonrecurring charges. In 1999, regulated utility earnings before the extraordinary charge increased compared to 1998 mostly because we had higher electricity and gas system sales that year, and we settled a capacity contract with PECO Energy Company in 1998 that had a negative impact on earnings in that year. This increase was offset partially by higher depreciation and amortization expense mostly due to the $75.0 million amortization of the regulatory asset recorded in 1999 for the reduction of our generation plant under the Restructuring Order, which reduced 1999 earnings by $48.8 million. In 1999, earnings from our domestic merchant energy business before nonrecurring charges increased compared to 1998 mostly because of higher earnings from our power marketing operation. In 1999, earnings from our other nonregulated businesses before nonrecurring charges increased compared to 1998 mostly because of higher earnings from our Latin American and real estate and senior-living facilities operations. In the following sections, we discuss our earnings by business segment in greater detail. Domestic Merchant Energy Business - --------------------------------- Our domestic merchant energy business engages primarily in power marketing and domestic power generation. As discussed in the Current Issues--Electric Competition section, our domestic 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 domestic merchant energy business, and Constellation Power Source began selling to BGE the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Constellation Power Source obtains the energy and capacity to supply BGE's standard offer service obligations from affiliates that own Calvert Cliffs and BGE's former fossil plants, supplemented with energy and capacity purchased from the wholesale market as necessary. Constellation Power Source also manages our wholesale market price risk. In addition, effective July 1, 2000, domestic merchant energy business revenues include 90% of the competitive transition charges BGE collects from its customers (CTC revenues) and the portion of BGE's revenues providing for nuclear decommissioning costs. 30 Our earnings are exposed to various market risks as discussed in the Market Risk section. For example, our earnings are exposed to the risks of the competitive wholesale electricity market to the extent that our domestic merchant energy business has to purchase energy and/or capacity to meet obligations to supply power or meet other energy-related contractual arrangements at prices which may approach or exceed the applicable fixed sales price obligations. If the price of obtaining energy in the wholesale market exceeds the fixed sales price, our earnings would be adversely affected. We also are affected by operational risk, that is, the risk that a generating plant will not be available to produce energy when the energy is required. Imbalances in demand and supply can occur not only because of plant outages, but also because of transmission constraints, or extreme temperatures (hot or cold) causing demand to exceed available supply. We cannot estimate the impact of the increased financial risks associated with the competitive wholesale electricity market. However, these financial risks could have a material impact on our financial results. Earnings 2000 1999 1998 - -------------------------------------------------------------------------- (In millions, except per share amounts) Revenues $992.0 $212.9 $147.3 Operating expenses 534.3 111.1 47.8 Depreciation and amortization 80.9 5.0 3.0 Taxes other than income taxes 24.1 -- -- - -------------------------------------------------------------------------- Income from operations $352.7 $ 96.8 $ 96.5 ========================================================================== Net income $206.8 $ 52.4 $ 53.1 ========================================================================== Total earnings per share before nonrecurring charges included in operations: $ 1.48 $ .44 $ .36 Deregulation transition cost (.10) -- -- Write-down of power projects -- (.09) -- - -------------------------------------------------------------------------- Earnings per share $ 1.38 $ .35 $ .36 ========================================================================== Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 2 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Revenues - -------- Our 2000 domestic merchant energy revenues increased $779.1 million compared to 1999 mostly because of: . a $581.0 million increase related to providing BGE the energy and capacity required to meet its standard offer service obligation effective July 1, 2000, . a $110.0 million increase related to CTC and decommissioning revenues included in the domestic merchant energy business effective July 1, 2000, and . higher revenues from our power marketing and domestic generation operations. Our 1999 domestic merchant energy revenues increased $65.6 million compared to 1998 mostly because of higher revenues from our power marketing operation offset partially by lower revenues from our domestic generation operation. We discuss the revenues for our power marketing and domestic generation operations in the sections below. Power Marketing - --------------- Power marketing revenues increased during 2000 compared to 1999 mostly because of higher transaction volumes in the Mid-Atlantic, Texas, and West regions, offset partially by lower margins. Power marketing revenues increased during 1999 compared to 1998 mostly because of higher transaction margins and volumes. Constellation Power Source uses 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 Note 1. As a result of the nature of its operations and the use of mark-to-market accounting, Constellation Power Source's revenues and earnings will fluctuate. We cannot predict these fluctuations, but the effect on our revenues and earnings could be material. The primary factors that cause these fluctuations are: . the number and size of new transactions, . the magnitude and volatility of changes in commodity prices and interest rates, and . the number and size of open commodity and derivative positions Constellation Power Source holds or sells. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative positions 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 assets and liabilities from power marketing and trading activities, and such variations could be material. Assets and liabilities from energy trading activities (as shown in our Consolidated Balance Sheets) increased significantly at December 31, 2000 compared to December 31, 1999 because of business growth during the period and increased market prices at the end of 2000. 31 Domestic Generation - ------------------- Our domestic generation revenues increased during 2000 compared to 1999 mostly because of three factors: . Our domestic generation operation recognized $13.3 million on the termination of an operating arrangement and the sale of certain subsidiaries. In April 2000, Constellation Operating Services, Inc. (COSI), a subsidiary of Constellation Power, Inc., ended its exclusive arrangement with Orion to operate Orion's facilities. Orion purchased from COSI the four subsidiary companies formed to operate power plants owned by Orion. . In November 2000, our domestic generation operation recorded a $19.2 million gain on the sale of approximately 3.2 million shares of Orion stock. . In 1999, our domestic generation operation recorded a write-off of two geothermal power projects as discussed below, which had a negative impact in that year. In 1999, our domestic generation revenues decreased compared to 1998 mostly because of three factors: . Our domestic generation operation wrote-off two geothermal power projects that totaled $21.4 million. These write-offs occurred because the expected future cash flows from the projects were less than the investment in the projects. For the first project, this resulted from the inability to restructure certain project agreements. For the second project, the water temperature of the geothermal resource used by one of the plants for production declined. . In 1998, our domestic generation operation recorded a $17.2 million gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power purchase agreement. . Revenues from our California power purchase agreements decreased as discussed below. California Power Purchase Agreements - ------------------------------------ Our domestic generation operation has $297.9 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Under these agreements, the electricity rates changed from fixed rates to variable rates beginning in 1996. In 2000, the last four projects transitioned to variable rates. In 1999 and prior years, the projects that transitioned to variable rates had lower revenues under variable rates than they did under fixed rates. In 2000, the prices received under these agreements were higher due to increases in the variable-rate pricing terms. However, due to the uncertainties in California, the recent increases in prices may not be indicative of future prices. We discuss the developments in California in the Current Issues-- Electric Competition section. We also describe these projects and the transition process in Note 3 and Note 10. Operating Expenses - ------------------ During 2000, domestic merchant energy operating expenses increased $423.2 million compared to 1999 mostly because of three factors: . An increase of $191.6 million in fuel costs and $157.2 million in operations and maintenance costs. These costs were associated with the generation plants that were transferred from BGE effective July 1, 2000. . A $24.0 million deregulation transition cost in June 2000 to a third party incurred by our power marketing operation to provide BGE's standard offer service requirements. . An increase in power marketing operating expenses due to the growth of the operation. During 1999, domestic merchant energy operating expenses increased $63.3 million compared to 1998 mostly because of the growth in our power marketing operation. Depreciation and Amortization Expense - ------------------------------------- In 2000, domestic merchant energy depreciation and amortization expense increased $75.9 million compared to 1999 mostly because of $73.8 million of expenses associated with the generation plants that were transferred from BGE effective July 1, 2000. In 1999, domestic merchant energy depreciation and amortization expense was about the same compared to 1998. Taxes Other than Income Taxes - ----------------------------- In 2000, domestic merchant energy taxes other than income taxes increased $24.1 million compared to 1999 because of $23.8 million of taxes other than income taxes associated with the generation plants that were transferred from BGE effective July 1, 2000. In 1999, domestic merchant energy taxes other than income taxes were the same compared to 1998. 32 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 domestic merchant energy business on that date. Earnings 2000 1999 1998 - ------------------------------------------------------------------------------ (In millions, except per share amounts) Electric revenues $2,135.2 $2,260.0 $2,220.8 Electric fuel and purchased energy 870.7 487.7 516.7 Operations and maintenance 454.2 629.6 630.5 Depreciation and amortization 319.9 376.4 313.0 Taxes other than income taxes 157.8 188.9 182.3 - ------------------------------------------------------------------------------ Income from operations $ 332.6 $ 577.4 $ 578.3 ============================================================================== Net income $ 102.3 $ 198.8 $ 259.6 ============================================================================== Total earnings per share before nonrecurring charges included in operations: $ .71 $ 1.81 $ 1.75 TVSERP (.03) -- -- Hurricane Floyd -- (.03) -- Extraordinary loss -- (.44) -- - ------------------------------------------------------------------------------ Earnings per share $ .68 $ 1.34 $ 1.75 ============================================================================== Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 2 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Electric Revenues - ----------------- The changes in electric revenues in 2000 and 1999 compared to the respective prior year were caused by: 2000 1999 - -------------------------------------------------------- (In millions) Electric system sales volumes $ 40.9 $41.3 Rates (119.9) 4.5 Fuel rate surcharge 12.6 -- - -------------------------------------------------------- Total change in electric revenues from electric system sales (66.4) 45.8 Interchange and other sales (58.3) (8.7) Other (0.1) 2.1 - -------------------------------------------------------- Total change in electric revenues $(124.8) $39.2 ======================================================== Electric System Sales Volumes - ----------------------------- "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. These sales do not include interchange sales and sales to others. The percentage changes in our electric system sales volumes, by type of customer, in 2000 and 1999 compared to the respective prior year were: 2000 1999 - ------------------------------------------ Residential 2.9% 3.5% Commercial 3.5 2.6 Industrial 2.9 (5.1) In 2000, we sold more electricity to residential customers compared to 1999 due to the colder winter weather, higher usage per customer, and an increased number of customers, offset partially by mild summer weather. We sold more electricity to commercial customers mostly due to higher usage per customer and an increased number of customers. We sold more electricity to industrial customers due to higher usage by Bethlehem Steel and an increased number of customers, offset partially by lower usage by other industrial customers. Usage was higher at Bethlehem Steel as a result of a 1999 shut down for a planned upgrade to their facilities that temporarily reduced their electricity consumption. In 1999, we sold more electricity to residential customers due to higher usage per customer, colder winter weather, and an increased number of customers compared to 1998. This increase was offset partially by milder spring and early summer weather. We sold more electricity to commercial customers mostly due to higher usage per customer, an increased number of customers, and colder winter weather. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased. This decrease was offset partially by an increase in the number of industrial customers. Rates - ----- Prior to July 1, 2000, our rates primarily consisted of an electric base rate and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled its rates to show separate components for delivery service, competitive transition charges, standard offer service (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 domestic merchant energy business effective July 1, 2000. In 2000, rate revenues decreased compared to 1999 mostly because of the $29.9 million decrease caused by the 6.5% annual residential rate reduction, and the $110.0 million transfer of revenues to the domestic merchant energy business discussed above. This was offset partially by higher fuel rate revenues during the first half of 2000. In 1999, rate revenues increased compared to 1998 because of higher fuel rate revenues. Fuel rate revenues increased mostly because we sold more electricity. 33 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. Interchange and Other Sales - --------------------------- "Interchange and other sales" are sales in the PJM energy market and to others. PJM is an ISO that operates a regional power pool with members that include many wholesale market participants, as well as BGE, and other utility companies. Prior to the implementation of customer choice, BGE sold energy to PJM members and to others after it had satisfied the demand for electricity in its own system. Effective July 1, 2000, BGE no longer engages in interchange sales. These activities are now included in our domestic merchant energy business which resulted in a decrease in interchange and other sales for the second half of 2000 compared to 1999. In addition, BGE had lower interchange and other sales during the first half of 2000 when increased demand for system sales reduced the amount of energy BGE had available for off-system sales. In 1999, interchange and other sales revenues decreased compared to 1998 mostly because higher demand for system sales reduced the amount of energy BGE had available for off-system sales. Electric Fuel and Purchased Energy Expenses - ------------------------------------------- 2000 1999 1998 - ----------------------------------------------------------------- (In millions) Actual costs $868.0 $558.0 $525.7 Net recovery (deferral) of costs under electric fuel rate clause 2.7 (70.3) (9.0) - ----------------------------------------------------------------- Total electric fuel and purchased energy expense $870.7 $487.7 $516.7 ================================================================= Actual Costs - ------------ In 2000, our actual costs of fuel and purchased energy were higher compared to 1999 mostly because of the deregulation of our electric generation. As discussed in the Current Issues--Electric Competition section, effective July 1, 2000, 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 domestic merchant energy business. In 2000, the cost of energy BGE purchased from our domestic merchant energy business was $581.0 million. The higher amount paid for purchased energy is offset by the absence of $191.6 million in fuel costs, and lower operations and maintenance, depreciation, taxes, and other costs at BGE as a result of no longer owning and operating the transferred electric generation plants. Prior to July 1, 2000, BGE's purchased fuel and energy costs only included actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others. In 1999, our actual costs of fuel to generate electricity and electricity we bought from others were higher compared to 1998 mostly because the price of electricity we bought from others was higher. The price of electricity changes based on market conditions and contract terms. This increase was offset partially by our settlement of a capacity contract with PECO in 1998. 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 are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. In 2000, the net deferral of costs under the electric fuel rate clause decreased compared to 1999 due to the discontinuation of the fuel rate clause effective July 1, 2000. In 1999, the net deferral of costs under the electric fuel rate clause increased compared to 1998 because the 1999 deferral reflected higher purchased power costs, especially during record-setting summer peak loads. Electric Operations and Maintenance Expenses - -------------------------------------------- In 2000, regulated electric operations and maintenance expenses decreased $175.4 million compared to 1999 mostly because effective July 1, 2000, $157.2 million of costs were no longer incurred by this business segment. These costs were associated with the electric generation assets that were transferred to the domestic merchant energy business. In addition, 1999 operations and maintenance expenses included costs for system restoration activities related to Hurricane Floyd and a major winter ice storm, and costs associated with the preparation for the year 2000 (Y2K). These costs had a negative impact in that year. These decreases are offset partially by the $7.0 million of expense recognized in 2000 for electric business employees that elected to participate in the TVSERP. 34 In 1999, regulated electric operations and maintenance expenses were about the same compared to 1998. In 1999, operations and maintenance expenses included the costs for system restoration activities related to Hurricane Floyd and a major winter ice storm. This was offset by lower employee benefit costs in 1999 and a 1998 $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed. Electric Depreciation and Amortization Expense - ---------------------------------------------- In 2000, regulated electric depreciation and amortization expense decreased $56.5 million compared to 1999 mostly because of the absence of $73.8 million of depreciation and amortization expense associated with the transfer of the generation assets. This decrease was offset partially by more electric plant in service (as our level of plant in service changes, the amount of depreciation and amortization expense changes) and higher amortization associated with regulatory assets. In 1999, regulated electric depreciation and amortization expense increased $63.4 million compared to 1998 mostly because of the $75.0 million amortization of the regulatory asset for the reduction in generation plant provided for in the Restructuring Order. This increase was offset partially by lower amortization of deferred electric conservation expenditures due to the write-off of a portion of these expenditures that will not be recovered under the Restructuring Order. We discuss the accounting implications of the Restructuring Order further in Note 4. Electric Taxes Other Than Income Taxes - -------------------------------------- In 2000, regulated electric taxes other than income taxes decreased $31.1 million compared to 1999. This was mostly due to two factors: . regulated electric taxes other than income taxes reflect the absence of $23.8 million of taxes other than income taxes associated with the generation assets that were transferred to the domestic merchant energy business effective July 1, 2000, and . comprehensive changes to the tax laws. The comprehensive tax law changes are discussed further in Note 4. In 1999, regulated electric taxes other than income taxes increased slightly due to higher property and franchise taxes associated with increased electric revenues. Regulated Gas Business - ---------------------- Earnings 2000 1999 1998 - ---------------------------------------------------------------------- (In millions, except per share amounts) Gas revenues $611.6 $488.1 $451.1 Gas purchased for resale 350.6 233.8 209.4 Operations and maintenance 100.6 97.7 97.7 Depreciation and amortization 46.2 44.9 45.4 Taxes other than income taxes 34.8 34.5 32.5 - ---------------------------------------------------------------------- Income from operations $ 79.4 $ 77.2 $ 66.1 ====================================================================== Net income $ 30.6 $ 33.0 $ 26.1 ====================================================================== Earnings per share $ .20 $ .22 $ .18 ====================================================================== Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 2 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. 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 2000 and 1999 compared to the respective prior year were caused by: 2000 1999 - ------------------------------------------------- (In millions) Gas system sales volumes $ 34.5 $ 8.0 Base rates 2.7 2.2 Weather normalization (26.7) 4.5 Gas cost adjustments 54.7 19.8 - ------------------------------------------------- Total change in gas revenues from gas system sales 65.2 34.5 Off-system sales 58.1 2.0 Other 0.2 0.5 - ------------------------------------------------- Total change in gas revenues $123.5 $37.0 ================================================= 35 Gas System Sales Volumes - ------------------------ The percentage changes in our gas system sales volumes, by type of customer, in 2000 and 1999 compared to the respective prior year were: 2000 1999 - --------------------------------------------------- Residential 13.0% 9.2% Commercial 12.8 12.7 Industrial (2.1) (4.8) In 2000, we sold more gas to residential and commercial customers compared to 1999 due to higher usage per customer, colder weather, and an increased number of customers. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers, offset partially by an increased number of customers. In 1999, we sold more gas to residential customers mostly for two reasons: colder winter weather and an increased number of customers. This was offset partially by lower usage per customer. We sold more gas to commercial customers mostly because of higher usage per customer, colder winter weather, and an increased number of customers. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers. Base Rates - ---------- In 2000, base rate revenues increased slightly compared to 1999 mostly because the Maryland PSC authorized a $6.4 million annual increase in our base rates effective June 22, 2000. In 1999, base rate revenues increased compared to 1998 mostly because of the $16.0 million annual increase in our base rates approved by the Maryland PSC effective March 1, 1998. 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. 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, and does not significantly impact earnings. Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales and are included in gas system sales volumes. In 2000 and 1999, gas cost adjustment revenues increased compared to the respective prior year mostly because we sold more gas at a higher price. In 2000, the revenue increase reflects the significant increase in natural gas prices. 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). In 2000, revenues from off-system gas sales increased compared to 1999 mostly because we sold more gas off-system at significantly higher prices. In 1999, revenues from off-system gas sales were about the same compared to 1998. 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. In 2000, our gas costs increased compared to 1999 mostly because we bought more gas for off-system sales and all of the gas purchased was at a higher price due to the significant increase in natural gas prices during the year. In 1999, actual gas costs increased compared to 1998 mostly because we sold more gas. Other Gas Operating Expenses - ---------------------------- In 2000 and 1999, other gas operating expenses were about the same compared to the respective prior year. 36 Other Nonregulated Businesses - ----------------------------- Earnings 2000 1999 1998 - ------------------------------------------------------------------------- (In millions, except per share amounts) Revenues $740.3 $858.1 $583.0 Operating expenses 638.0 821.5 569.4 Depreciation and amortization 23.0 23.5 13.9 Taxes other than income taxes 4.3 3.9 4.6 - ------------------------------------------------------------------------- Income (loss) from operations $ 75.0 $ 9.2 $ (4.9) ========================================================================= Net income (loss) $ 5.6 $(24.1) $(32.9) ========================================================================= Total earnings per share before nonrecurring charges included in operations: $ .04 $ .01 $ (.09) Write-down of power project -- (.03) -- Write-down of financial investment -- (.11) -- Write-down of real estate and senior-living investments -- (.04) (.10) Write-off of energy services investment -- -- (.04) - ------------------------------------------------------------------------- Earnings per share $ .04 $ (.17) $ (.23) ========================================================================= Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 2 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. In 2000, earnings from our other nonregulated businesses increased compared to 1999 mostly because of better market performance of certain of our financial investments. In addition, in 1999, we wrote-down a financial investment, our investment in a generating company in Bolivia, and certain senior-living facilities, which had negative impacts in that year. These increases were offset partially by lower earnings from our Latin American operation primarily due to increased operating expenses in Guatemala. In 1999, earnings from our other nonregulated businesses increased compared to 1998 mostly because of higher earnings from our Latin American and real estate and senior-living facilities operations. This increase was offset partially by lower earnings from our financial investments operation. In 1999, earnings from our Latin American operation increased mostly because of higher earnings from the electric distribution company in Panama compared to 1998. In October 1998, an investment group, in which subsidiaries of our Latin American operation hold an 80% interest, purchased 51% of the Panamanian company. This was offset partially by a $4.5 million after-tax write-down of our investment in a generating company in Bolivia to reflect the current fair value of this investment. This write-down was a result of our December 1999 decision to exit the Latin American portion of our business as part of our strategy to improve our competitive position. In 1999, earnings from our real estate and senior-living facilities operation increased compared to 1998 mostly because of: . a $15.4 million after-tax write-down of its investment in Church Street Station, an entertainment, dining, and retail complex in Orlando, Florida in 1998 that negatively impacted earnings that year, and . an increase in earnings from its investment in Corporate Office Properties Trust (COPT) in 1999. We discuss the investment in COPT in Note 3. This increase was offset partially by a $5.8 million after-tax write-down of certain senior-living facilities related to the proposed sale of these facilities in 1999 as discussed below. Additionally, in 1998, our energy products and services operation recorded a $5.5 million after-tax write-off of an investment in, and certain of our product inventory from, an automated electric distribution equipment company. In 1999, our financial investments operation announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE, another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. As a result, our financial investments operation wrote-down its $94.2 million investment in Capital Re stock by $16.0 million after-tax to reflect the closing price of the business combination. This write-down of Capital Re was offset partially by better market performance of other financial investments in 1999 compared to 1998. In 1999, our senior-living facilities operation entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terminated in November 1999. As a result, our senior-living facilities operation engaged a third-party management company to manage its portfolio. However, our senior-living facilities operation recorded a $5.8 million after-tax write-down related to the proposed sale. Most of Constellation Real Estate Group's real estate and senior-living projects are in the Baltimore-Washington corridor. The area has had a surplus of available land in recent years and as a result these projects have been economically hurt. 37 Constellation Real Estate's projects have continued to incur carrying costs and depreciation over the years. Additionally, this operation has been charging interest payments to expense rather than capitalizing them for some undeveloped land where development activities have stopped. These carrying costs, depreciation, and interest expenses have decreased earnings and are expected to continue to do so. Cash flow from real estate and senior-living operations has not been enough to make the monthly loan payments on some of these projects. Cash shortfalls have been covered by cash obtained from the cash flows of, or additional borrowings by, other nonregulated subsidiaries. We consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate and senior-living projects. If we were to decide to sell our projects, we could have write-downs. In addition, if we were to sell our projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict. Depending on market conditions, we could also have material losses on any future sales. Our current real estate and senior-living strategy is to hold each project until we can realize a reasonable value for it. Under accounting rules, we are required to write down the value of a project to market value in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected cash flow from the project is less than the investment in the project. Consolidated Nonoperating Income and Expenses - -------------------------------------------- Fixed Charges - ------------- In 2000, fixed charges increased $16.4 million compared to 1999 mostly because we had more debt outstanding. In 1999, fixed charges decreased $5.6 million compared to 1998 mostly because we had less BGE preference stock outstanding. Income Taxes - ------------ In 2000, our total income taxes increased $43.7 million compared to 1999 mostly because we had higher taxable income from our nonregulated businesses and an increase in state and local taxes as a result of comprehensive changes to these laws. This increase was offset partially by lower taxable income at BGE. We discuss the comprehensive tax law changes in Note 4. In 1999, income taxes increased $8.7 million compared to 1998 because we had higher taxable income from both our regulated utility operations and our nonregulated businesses. FINANCIAL CONDITION Cash Flows 2000 1999 1998 - ---------------------------------------------------------------------- (In millions) Cash provided by (used in): Operating activities $ 850.9 $ 679.0 $ 799.8 Investing activities (1,106.5) (615.1) (711.3) Financing activities 345.6 (144.9) (77.4) In 2000 and 1999, cash provided by operations changed compared to the respective prior year mostly because of changes in working capital requirements. In 2000, we used more cash for investing activities compared to 1999 mostly due to substantial increases in our domestic merchant energy capital expenditures to support our growth initiatives. In 1999, we used less cash for investing activities compared to 1998 mostly due to lower investments in Latin American power projects and in the real estate and senior-living facilities operation. This was offset partially by a $97.7 million increase in the investment in Orion, an increase in our investment in domestic power projects, and an increase in capital expenditures by our regulated utility business. In 2000, we had more cash from financing activities compared to 1999 mostly because we issued more long-term debt and common stock. This was offset partially by an increase in net maturities of short-term borrowings and we repaid more long-term debt. In 1999, we used more cash for financing activities compared to 1998 mostly because we repaid more long-term debt and issued less long-term debt and common stock. This was offset partially by a decrease in the redemption of BGE preference stock and an increase in our net short-term borrowings. Security Ratings - ---------------- Independent credit-rating agencies rate Constellation Energy 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. Constellation Energy and BGE's securities ratings at December 31, 2000 were: Standard & Poors Moody's Rating Investors Fitch Group Service IBCA - --------------------------------------------------------------------- Constellation Energy - -------------------- Unsecured Debt A- A3 A- BGE - --- Mortgage Bonds AA- A1 A+ Unsecured Debt A A2 A Trust Originated Preferred Securities and Preference Stock A- "a2" A- 38 CAPITAL RESOURCES Our business requires a great deal of capital. Our actual consolidated capital requirements for the years 1998 through 2000, along with the estimated annual amounts for the years 2001 through 2003, are shown in the table below. We will continue to have cash requirements for: . working capital needs including the payments of interest, distributions, and dividends, . capital expenditures, and . the retirement of debt and redemption of preference stock. Capital requirements for 2001 through 2003 include estimates of funding 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: . regulation, legislation, and competition, . BGE load requirements, . environmental protection standards, . the type and number of projects selected for development, . the effect of market conditions on those projects, . the cost and availability of capital, and . the availability of cash from operations. Our estimates are also subject to additional factors. Please see the Forward Looking Statements section. Effective July 1, 2000, all of BGE's generation assets were transferred to nonregulated subsidiaries of Constellation Energy. The discussion and table for capital requirements below include these generation assets as part of the utility's regulated electric business through June 30, 2000. After that date, the capital requirements are included in the domestic merchant energy business.
1998 1999 2000 2001 2002 2003 - ----------------------------------------------------------------------------------------------------------------- (In millions) Nonregulated Capital Requirements: Investment requirements: Domestic merchant energy $ 318 $ 260 $ 801* $1,420 $1,000 $1,790 Other 7 18 29 50 79 105 - ----------------------------------------------------------------------------------------------------------------- Total investment requirements 325 278 830 1,470 1,079 1,895 Retirement of long-term debt 232 189 295 406** 215 200 - ----------------------------------------------------------------------------------------------------------------- Total nonregulated capital requirements 557 467 1,125 1,876 1,294 2,095 Utility Capital Requirements: Capital expenditures: Regulated electric Generation (including nuclear fuel) 154 170 95 -- -- -- Transmission and distribution 161 173 170 174 171 173 - ----------------------------------------------------------------------------------------------------------------- Total regulated electric 315 343 265 174 171 173 Regulated gas 55 59 55 53 52 52 Common 35 34 30 32 26 20 - ----------------------------------------------------------------------------------------------------------------- Total capital expenditures 405 436 350 259 249 245 Retirement of long-term debt and redemption of preference stock 222 342 402 394 320 286 - ----------------------------------------------------------------------------------------------------------------- Total utility capital requirements 627 778 752 653 569 531 - ----------------------------------------------------------------------------------------------------------------- Total capital requirements $1,184 $1,245 $1,877 $2,529 $1,863 $2,626 =================================================================================================================
*Effective July 1, 2000, includes $110.6 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business. **Amount does not include $1.2 billion in Constellation Energy debt that would be redeemed at or prior to business separation. 39 Capital Requirements - -------------------- Domestic Merchant Energy Business - --------------------------------- Our domestic merchant energy business will require additional funding for growing its power marketing operation and developing and acquiring power projects. Our domestic merchant energy business investment requirements include the planned purchase of the Nine Mile Point nuclear power plant for $815 million, including fuel, and the planned construction of 1,100 megawatts of peaking capacity in the Mid-Atlantic and Mid-West regions which are expected to be operational by the summer of 2001. An additional 6,700 megawatts of peaking and combined cycle production facilities are scheduled for completion in 2002 and beyond in various regions of North America. Longer range, our plans are to control approximately 30,000 megawatts of generation capacity by 2005. For further information see the Strategy section. Electric Generation - ------------------- Electric construction expenditures for our regulated electric business include improvements to generating plants and costs for replacing the steam generators at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are reflected in our domestic merchant energy business. In March 2000, we received the license extension from the Nuclear Regulatory Commission (NRC) that extends our operating licenses at Calvert Cliffs to 2034 for Unit 1 and 2036 for Unit 2. If we do not replace the steam generators, we will not be able to operate these units through our operating license periods. We expect the steam generator replacement to occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be: . $ 63 million in 2001, . $ 91 million in 2002, and . $ 60 million in 2003. Additionally, our estimates of future electric generation construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction regulations as follows: . $ 85 million in 2001, . $ 37 million in 2002, and . $ 7 million in 2003. We discuss the NOx regulations and timing of expenditures in Note 10. Regulated Electric Transmission and Distribution and Gas - -------------------------------------------------------- Regulated electric transmission and distribution and gas construction expenditures primarily include new business construction needs and improvements to existing facilities. Funding for Capital Requirements - -------------------------------- On October 23, 2000, we announced initiatives designed to advance our growth strategies in the domestic merchant energy business and a change in our common stock dividend policy effective April 2001, as discussed in the Strategy section. As part of these initiatives, we expect to redeem all of the outstanding debt at Constellation Energy at or prior to the separation of our domestic merchant energy business and remaining businesses. The redemption will occur through a combination of open market purchases, tender offers, and redemption calls. We expect to fund this redemption with short-term debt or other credit facilities, and to refinance this debt longer term after the separation. On March 26, 2001, we issued 12 million shares of common stock with net proceeds of $471.4 million. Domestic Merchant Energy Business - --------------------------------- Funding for the expansion of our domestic merchant energy business is expected from internally generated funds, commercial paper, long-term debt, equity, leases, and other financing instruments issued by Constellation Energy and its subsidiaries. Specifically related to the Nine Mile Point acquisition, one-half of the purchase price, or $407.5 million, is due at the closing of the transaction and the remainder is being financed through the sellers in a note to be repaid over five years with an interest rate of 11.0%. We expect to close the transaction with funds from available sources at that time. Payments on the note over the five years are expected to come from internally generated funds. 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. When our domestic merchant energy business separates from our remaining businesses, it initially expects to reinvest its earnings to fund its growth and not to pay a dividend. Constellation Energy has a commercial paper program where it can issue up to $500 million in short-term notes to fund its nonregulated businesses. To support its commercial paper program, Constellation Energy maintains two revolving credit agreements totaling $565 million, of which one facility can also issue letters of credit. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. BGE - --- Funding for utility capital expenditures is expected from internally generated funds, 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. At December 31, 2000, FERC authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains $193 million in annual committed bank lines of credit and has $25 million in bank 40 revolving credit agreements to support the commercial paper program. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper. During the three years from 2001 through 2003, we expect our regulated utility business to provide at least 110% of the cash needed to meet the capital requirements for its operations, excluding cash needed to retire debt. Other Nonregulated Businesses - ----------------------------- BGE Home Products & Services may meet capital requirements through sales of receivables. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs. If we can get a reasonable value for our real estate projects, senior-living facilities, Latin American operation, 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. We discuss the real estate and senior-living facilities operation and market conditions in the Other Nonregulated Businesses section. We discuss our short-term borrowings in Note 7 and long-term debt in Note 8. MARKET RISK We are exposed to market risk, including changes in interest rates, certain commodity prices, equity prices, and foreign currency. To manage our market risk, we may enter into various derivative instruments including swaps, forward contracts, futures contracts, and options. Effective July 1, 2000, we are subject to additional market risk associated with the purchase and sale of energy as discussed in the Current Issues section. We discuss our market risk further in Note 1. In this section, we discuss our current market risk and the related use of derivative instruments. Interest Rate Risk - ------------------ We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt. The following table provides information about our obligations that are sensitive to interest rate changes: Principal Payments and Interest Rate Detail by Contractual Maturity Date
Fair value at 2001 2002 2003 2004 2005 Thereafter Total Dec. 31, 2000 - ----------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Long-term debt - -------------- Variable-rate debt $317.6 $208.0 $200.2 $ 7.6 $ 5.4 $ 593.0 $1,331.8 $1,243.3 Average interest rate 6.97% 7.30% 7.26% 8.42% 8.62% 5.99% 6.64% Fixed-rate debt $482.5 $327.1 $286.3 $156.0 $347.6 $1,140.0 $2,739.5 $2,819.9 Average interest rate 7.08% 7.01% 6.50% 5.80% 7.72% 6.85% 6.92%
Commodity Price Risk - -------------------- We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. Domestic Merchant Energy Business - --------------------------------- Our domestic merchant energy business is exposed to market risk from the power marketing operation of Constellation Power Source and from our electric generation operations. Constellation Power Source manages the commodity price risk inherent in its power marketing activities on a portfolio basis, subject to established trading and risk management policies. Commodity price risk arises from the potential for changes in the value of energy commodities and related derivatives due to: changes in commodity prices, volatility of commodity prices, and fluctuations in interest rates. A number of factors associated with the structure and operation of the electricity market significantly influence the level and volatility of prices for energy commodities and related derivative products. These factors include: . seasonal changes in demand, . hourly fluctuations in demand due to weather conditions, . available supply resources, . transportation availability and reliability within and between regions, . procedures used to maintain the integrity of the physical electricity system during extreme conditions, and . changes in the nature and extent of federal and state regulations. 41 These 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: . weather conditions, . market liquidity, . capability and reliability of the physical electricity and gas systems, and . the nature and extent of electricity deregulation. Constellation Power Source uses various methods, including a value at risk model, to measure its exposure to market risk. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price and volatility data. Constellation Power Source calculates value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, Constellation Power Source estimates variances and correlation using historical market movements over the most recent rolling three-month period. The value at risk amount represents the potential loss in the fair value of assets and liabilities from trading activities over a one-day holding period with a 99.6% confidence level. Using this confidence level, Constellation Power Source would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. Constellation Power Source's value at risk was $13.7 million as of December 31, 2000 compared to $7.2 million as of December 31, 1999. The average, high, and low value at risk for the year ended December 31, 2000 was $13.1 million, $24.3 million, and $6.3 million, respectively. Constellation Power Source's value at risk calculation includes all assets and liabilities from its power marketing and trading activities, including energy commodities and derivatives that do not require cash settlements. We believe that this represents a more complete calculation of our value at risk. Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive market for electricity and related derivatives, and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of assets and liabilities from power marketing and trading activities could differ from the calculated value at risk, and such changes could have a material impact on our financial results. Please refer to the Forward Looking Statements section. We discuss Constellation Power Source's operation in the Domestic Merchant Energy Business section and in Note 1. Our domestic merchant energy business conducts electric generation operations primarily through Constellation Power Source Generation, Calvert Cliffs, and Constellation Power. Presently, the majority of the generating capacity controlled by our domestic merchant energy business is used to provide standard offer service to BGE. However, beginning in July 2002, we expect approximately 1,000 megawatts of industrial customer load will leave standard offer service. The remainder of the standard offer service arrangement with BGE terminates on June 30, 2003. Additionally, we plan to expand our generation operations as discussed in the Strategy section. As a result, our domestic merchant energy business has a substantial and increasing amount of generating capacity that is subject to future changes in wholesale electricity prices and has fuel requirements that are subject to future changes in coal, natural gas, and oil prices. Additionally, if one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed price sale commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices. Constellation Power Source manages the commodity price risk of our electric generation operations as part of its overall portfolio. Additionally, the domestic merchant energy business may enter into fixed-price contracts to hedge a portion of its exposure to future electricity and fuel commodity price risk. Regulated Electric Business - --------------------------- The standard offer service arrangement between BGE and Constellation Power Source ends June 30, 2003. Under the Restructuring Order, effective July 1, 2000, BGE's residential rates are frozen for a six-year period and its commercial and industrial rates are frozen for four to six years. As a result, BGE will be subject to commodity price risk beginning July 1, 2003 upon termination of the existing standard offer arrangement. In accordance with the Restructuring Order, BGE will competitively bid the standard offer service supply for the remaining period of the rate freeze subsequent to June 30, 2003. During the remaining period of BGE's rate freeze, BGE will be unable to pass through to its customers any increase in the market price of electricity it must purchase to meet the standard offer service load. Our regulated electric business is evaluating various alternatives to minimize the market risk after June 30, 2003. Regulated Gas Business - ---------------------- Our regulated gas business may enter into gas futures, options, and swaps to hedge its price risk under our market based rate incentive mechanism and our off-system gas sales program. We discuss this further in Note 1. At December 31, 2000 and 1999, our exposure to commodity price risk for our regulated gas business was not material. 42 Credit Risk - ----------- We are exposed to credit risk, primarily through Constellation Power Source. Credit risk is the loss that may result from a counterparty's nonperformance. Constellation Power Source uses credit policies to control its credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements. However, due to the possibility of extreme volatility in the prices of electricity commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity Constellation Power Source had contracted for), Constellation Power Source could sustain a loss that could have a material impact on our financial results. Our domestic merchant energy business sells electricity to two California investor-owned utilities under long-term power purchase agreements that recently were downgraded by rating agencies to below investment grade. We discuss the credit and other exposures under these agreements in the Current Issues section. Equity Price Risk - ----------------- We are exposed to price fluctuations in equity markets primarily through our financial investments operation and our nuclear decommissioning trust fund. We are required by the NRC to maintain a trust to fund the costs of decommissioning Calvert Cliffs. We believe our exposure to fluctuations in equity prices will not have a material impact on our financial results. We discuss our nuclear decommissioning trust fund in more detail in Note 1. We also describe our financial investments in more detail in Note 3. Foreign Currency Risk - --------------------- We are exposed to foreign currency risk primarily through our Latin American operation. Our Latin American operation has $255.9 million invested in international power generation and distribution projects as of December 31, 2000. To manage our exposure to foreign currency risk, the majority of our contracts are denominated in or indexed to the U.S. dollar. At December 31, 2000 and 1999, foreign currency risk was not material. We discuss our international projects in the Other Nonregulated Businesses section. - -------------------------------------------------------------------------------- Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading Market Risk. 43 Item 8. Financial Statements and Supplementary Data REPORT OF MANAGEMENT The management of the Companies is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management's best estimates and judgments of known conditions. The Companies maintain an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Companies' assets are protected. The Companies' staff of internal auditors, which reports directly to the Chairman of the Board, conducts periodic reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, independent accountants, audit the financial statements and express their opinion on them. They perform their audit in accordance with auditing standards generally accepted in the United States of America. The Audit Committee of the Board of Directors, which consists of four outside Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee. /s/ Christian H. Poindexter /s/ David A. Brune - ------------------------------- ------------------ Christian H. Poindexter David A. Brune Chairman of the Board Chief Financial Officer and Chief Executive Officer REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a) 1. present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries and of Baltimore Gas and Electric Company and Subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a) 2. of this Form 10-K present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Companies' management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. We have also previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets and statement of capitalization of Baltimore Gas and Electric Company as of December 31, 1998, 1997 and 1996, and the related consolidated statements of income, comprehensive income, cash flows, common shareholders' equity and income taxes for the years ended December 31, 1997 and 1996 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. included in the Selected Financial Data for each of the five years in the period ended December 31, 2000, and the information set forth in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company included in the Selected Financial Data for each of the five years in the period ended December 31, 2000, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived. /s/ PricewaterhouseCoopers LLP - ------------------------------ PricewaterhouseCoopers LLP Baltimore, Maryland January 17, 2001 44
CONSOLIDATED STATEMENTS OF INCOME -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Nonregulated revenues $1,140.0 $1,050.9 $ 717.8 Regulated electric revenues 2,134.7 2,258.8 2,219.2 Regulated gas revenues 603.8 476.5 449.4 - ------------------------------------------------------------------------------------------------------- Total revenues 3,878.5 3,786.2 3,386.4 Expenses Operating expenses 2,347.3 2,349.2 2,053.0 Depreciation and amortization 470.0 449.8 375.5 Taxes other than income taxes 221.0 227.3 219.4 - ------------------------------------------------------------------------------------------------------- Total expenses 3,038.3 3,026.3 2,647.9 - ------------------------------------------------------------------------------------------------------- Income from Operations 840.2 759.9 738.5 Other Income 6.6 7.9 5.7 - ------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 846.8 767.8 744.2 Fixed Charges Interest expense (net) 258.2 241.5 238.8 BGE preference stock dividends 13.2 13.5 21.8 - ------------------------------------------------------------------------------------------------------- Total fixed charges 271.4 255.0 260.6 - ------------------------------------------------------------------------------------------------------- Income Before Income Taxes 575.4 512.8 483.6 Income Taxes 230.1 186.4 177.7 - ------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 345.3 326.4 305.9 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) -- (66.3) -- - ------------------------------------------------------------------------------------------------------- Net Income $ 345.3 $ 260.1 $ 305.9 ======================================================================================================= Earnings Applicable to Common Stock $ 345.3 $ 260.1 $ 305.9 ======================================================================================================= Average Shares of Common Stock Outstanding 150.0 149.6 148.5 Earnings Per Common Share and Earnings Per Common Share-- Assuming Dilution Before Extraordinary Item $ 2.30 $ 2.18 $ 2.06 Extraordinary Loss -- (.44) -- - ------------------------------------------------------------------------------------------------------- Earnings Per Common Share and Earnings Per Common Share--Assuming Dilution $ 2.30 $ 1.74 $ 2.06 ======================================================================================================= CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------- (In millions) Net Income $345.3 $260.1 $305.9 Other comprehensive income/(loss), net of taxes 22.1 (6.2) 1.2 - ------------------------------------------------------------------------------------------------------- Comprehensive Income $367.4 $253.9 $307.1 =======================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 45 CONSOLIDATED BALANCE SHEETS -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
At December 31, 2000 1999 - ----------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 182.7 $ 92.7 Accounts receivable (net of allowance for uncollectibles of $21.3 and $34.8, respectively) 738.5 578.5 Trading securities 189.3 136.5 Assets from energy trading activities 2,056.5 312.1 Fuel stocks 78.2 94.9 Materials and supplies 151.3 149.1 Prepaid taxes other than income taxes 73.5 72.4 Other 32.7 54.0 - ----------------------------------------------------------------------------------------- Total current assets 3,502.7 1,490.2 - ----------------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 290.3 310.1 Investments in power projects 517.5 513.9 Financial investments 161.0 145.4 Nuclear decommissioning trust fund 228.7 217.9 Net pension asset 93.2 99.5 Investment in Orion Power Holdings, Inc. 192.0 105.7 Other 123.0 154.3 - ----------------------------------------------------------------------------------------- Total investments and other assets 1,605.7 1,546.8 - ----------------------------------------------------------------------------------------- Property, Plant and Equipment Regulated property, plant and equipment Plant in service 4,780.3 8,620.1 Construction work in progress 75.3 222.3 Plant held for future use 4.5 13.0 - ----------------------------------------------------------------------------------------- Total regulated property, plant and equipment 4,860.1 8,855.4 Nonregulated generation property, plant and equipment 5,279.9 374.7 Other nonregulated property, plant and equipment 173.8 152.7 Nuclear fuel (net of amortization) 128.3 133.8 Accumulated depreciation (3,798.1) (3,559.1) - ----------------------------------------------------------------------------------------- Net property, plant and equipment 6,644.0 5,957.5 - ----------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 514.9 637.4 Other 117.3 51.9 - ----------------------------------------------------------------------------------------- Total deferred charges 632.2 689.3 - ----------------------------------------------------------------------------------------- Total Assets $12,384.6 $ 9,683.8 =========================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 46 CONSOLIDATED BALANCE SHEETS--CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES At December 31, 2000 1999 - --------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 243.6 $ 371.5 Current portion of long-term debt 906.6 808.3 Accounts payable 695.9 365.1 Liabilities from energy trading activities 1,586.8 163.8 Dividends declared 66.5 66.1 Accrued taxes 38.2 19.2 Other 212.6 209.4 - --------------------------------------------------------------------- Total current liabilities 3,750.2 2,003.4 - --------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,339.5 1,288.8 Postretirement and postemployment benefits 265.2 269.8 Deferred investment tax credits 101.4 109.6 Other 426.0 253.8 - --------------------------------------------------------------------- Total deferred credits and other liabilities 2,132.1 1,922.0 - --------------------------------------------------------------------- Capitalization Long-term debt 3,159.3 2,575.4 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 3,153.0 2,993.0 - --------------------------------------------------------------------- Total capitalization 6,502.3 5,758.4 - --------------------------------------------------------------------- Commitments, Guarantees, and Contingencies (see Note 10) Total Liabilities and Capitalization $12,384.6 $9,683.8 ===================================================================== See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 47 CONSOLIDATED STATEMENTS OF CASH FLOWS--CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
Year Ended December 31, 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 345.3 $ 260.1 $ 305.9 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss -- 66.3 -- Depreciation and amortization 524.8 505.9 427.8 Deferred income taxes 42.0 13.0 17.5 Investment tax credit adjustments (8.3) (8.6) (8.8) Deferred fuel costs 2.8 (61.1) (8.3) Accrued pension and postemployment benefits 27.9 36.1 41.6 Gain on sale of subsidiaries (13.3) -- -- Gain on sale of Orion Power Holdings, Inc. stock (19.2) -- -- Deregulation transition cost 24.0 -- -- Write-downs of real estate investments -- 9.6 23.7 Write-down of financial investment -- 26.2 -- Write-downs of power projects -- 28.5 -- Equity in earnings of affiliates and joint ventures (net) (5.3) (7.6) (54.5) Changes in assets from energy trading activities (1,744.4) (179.1) (123.6) Changes in liabilities from energy trading activities 1,423.0 64.8 90.4 Changes in other current assets (176.6) (216.4) 18.3 Changes in other current liabilities 352.1 121.0 77.0 Other 76.1 20.3 (7.2) - ----------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 850.9 679.0 799.8 - ----------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (1,079.0) (616.5) (730.2) Investment in Orion (101.5) (97.7) -- Contributions to nuclear decommissioning trust fund (13.2) (17.6) (17.6) Purchases of marketable equity securities (80.8) (27.3) (33.3) Sales of marketable equity securities 110.2 34.9 32.8 Other investments 57.8 109.1 37.0 - ----------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (1,106.5) (615.1) (711.3) - ----------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net (maturity) issuance of short-term borrowings (127.9) 371.5 (316.1) Proceeds from issuance of Long-term debt 1,374.0 302.8 831.3 Common stock 35.9 9.6 51.8 Reacquisition of long-term debt (697.0) (584.4) (355.2) Redemption of preference stock -- (7.0) (127.9) Common stock dividends paid (250.7) (251.1) (246.0) Other 11.3 13.7 84.7 - ----------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities 345.6 (144.9) (77.4) - ----------------------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 90.0 (81.0) 11.1 Cash and Cash Equivalents at Beginning of Year 92.7 173.7 162.6 - ----------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 182.7 $ 92.7 $ 173.7 ================================================================================================================= Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 268.2 $ 245.3 $ 236.7 Income taxes $ 184.7 $ 165.6 $ 164.3
Noncash Investing and Financing Activities: In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62 million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COPT received 14 operating properties and two properties under development from CREG. See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 48
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY--CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 2000, 1999, and 1998 Shares Amount Earnings Income Amount - ----------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, number of shares in thousands) Balance at December 31, 1997 147,667 $1,433.0 $1,432.5 $ 4.9 $2,870.4 Net income 305.9 305.9 Common stock dividend declared ($1.67 per share) (248.1) (248.1) Common stock issued 1,579 51.8 51.8 Other 0.3 0.3 Net unrealized gain on securities 1.8 1.8 Deferred taxes on net unrealized gain on securities (0.6) (0.6) - ----------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5 Net income 260.1 260.1 Common stock dividend declared ($1.68 per share) (251.3) (251.3) Common stock issued 310 9.6 9.6 Other (0.7) (0.7) Net unrealized loss on securities (9.6) (9.6) Deferred taxes on net unrealized loss on securities 3.4 3.4 - ----------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 149,556 1,494.0 1,499.1 (0.1) 2,993.0 Net income 345.3 345.3 Common stock dividend declared ($1.68 per share) (251.8) (251.8) Common stock issued 976 35.9 35.9 Other 8.8 (0.3) 8.5 Net unrealized gain on securities 33.9 33.9 Deferred taxes on net unrealized gain on securities (11.8) (11.8) - ----------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 150,532 $1,538.7 $1,592.3 $22.0 $3,153.0 ===========================================================================================================
See Notes to Consolidated Financial Statements. 49 CONSOLIDATED STATEMENTS OF CAPITALIZATION -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
At December 31, 2000 1999 - --------------------------------------------------------------------------------------------------------------------------- (In millions) Long-Term Debt Long-term debt of Constellation Energy 7 7/8% Notes, due April 1, 2005 $ 300.0 $ -- Floating rate notes, due April 4, 2003 200.0 -- Extendible notes, due June 21, 2010 300.0 -- Floating rate reset notes, due March 15, 2002 200.0 -- - --------------------------------------------------------------------------------------------------------------------------- Total long-term debt of Constellation Energy 1,000.0 -- - --------------------------------------------------------------------------------------------------------------------------- Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE effective July 1, 2000 Pollution control loan, due July 1, 2011 36.0 -- Port facilities loan, due June 1, 2013 48.0 -- Adjustable rate pollution control loan, due July 1, 2014 20.0 -- 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 -- Economic development loan, due December 1, 2018 35.0 -- 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 -- Floating rate pollution control loan, due June 1, 2027 8.8 -- 5 1/2% Installment series, due July 15, 2002 7.6 -- Loan under revolving credit agreement 34.0 33.0 Mortgage and construction loans Floating rate mortgage notes and construction loans, due through 2005 51.3 112.0 Other mortgage notes ranging from 4.25% to 9.65% due July 31, 2001 to November 1, 2033 20.3 30.8 Unsecured notes 287.0 511.0 - --------------------------------------------------------------------------------------------------------------------------- Total long-term debt of nonregulated businesses 670.0 686.8 - --------------------------------------------------------------------------------------------------------------------------- First Refunding Mortgage Bonds of BGE 5 1/2% Series, due July 15, 2000 transferred to nonregulated businesses effective July 1, 2000 -- 124.3 8 3/8% Series, due August 15, 2001 122.2 122.3 7 1/4% Series, due July 1, 2002 124.0 124.5 6 1/2% Series, due February 15, 2003 124.8 124.8 6 1/8% Series, due July 1, 2003 124.9 124.9 5 1/2% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 111.5 125.0 7 1/2% Series, due January 15, 2007 123.5 123.5 6 5/8% Series, due March 15, 2008 124.9 124.9 7 1/2% Series, due March 1, 2023 109.9 109.9 7 1/2% Series, due April 15, 2023 84.0 84.1 Tax-exempt debt transferred to nonregulated businesses effective July 1, 2000 -- 8.5 - --------------------------------------------------------------------------------------------------------------------------- Total First Refunding Mortgage Bonds of BGE 1,174.7 1,321.7 - --------------------------------------------------------------------------------------------------------------------------- Other long-term debt of BGE Floating rate reset notes, due October 19, 2001 200.0 -- Medium-term notes, Series B 23.1 60.0 Medium-term notes, Series C 25.5 101.0 Medium-term notes, Series D 128.0 128.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 200.0 200.0 Medium-term notes, Series H 27.0 177.0 6.75% Remarketable or redeemable securities, due December 15, 2012 173.0 -- Tax-exempt debt transferred to nonregulated businesses effective July 1, 2000 -- 269.8 - --------------------------------------------------------------------------------------------------------------------------- Total other long-term debt of BGE 976.6 1,135.8 - --------------------------------------------------------------------------------------------------------------------------- BGE 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 (5.4) (10.6) Current portion of long-term debt (906.6) (808.3) - --------------------------------------------------------------------------------------------------------------------------- Total long-term debt $3,159.3 $2,575.4 - ---------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. continued on next page 50
CONSOLIDATED STATEMENTS OF CAPITALIZATION -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES At December 31, 2000 1999 - ---------------------------------------------------------------------------------------------------------------------- (In millions) BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 $ 40.0 $ 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 - ---------------------------------------------------------------------------------------------------------------------- Total preference stock not subject to mandatory redemption 190.0 190.0 - ---------------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 150,531,716 and 149,556,416 shares issued and outstanding at December 31, 2000 and 1999, respectively. (At December 31, 2000 166,893 shares were reserved for the Employee Savings Plan and 12,061,756 shares were reserved for the Shareholder Investment Plan.) 1,538.7 1,494.0 Retained earnings 1,592.3 1,499.1 Accumulated other comprehensive income (loss) 22.0 (0.1) - ---------------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 3,153.0 2,993.0 - ---------------------------------------------------------------------------------------------------------------------- Total Capitalization $6,502.3 $5,758.4 ======================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 51 CONSOLIDATED STATEMENTS OF INCOME TAXES -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Income Taxes Current $ 196.4 $ 182.0 $ 169.0 - ------------------------------------------------------------------------------------------------------------- Deferred Change in tax effect of temporary differences 50.4 9.6 14.2 Change in income taxes recoverable through future rates 3.4 -- 3.9 Deferred taxes credited (charged) to shareholders' equity (11.8) 3.4 (0.6) - ------------------------------------------------------------------------------------------------------------- Deferred taxes charged to expense 42.0 13.0 17.5 Investment tax credit adjustments (8.3) (8.6) (8.8) - ------------------------------------------------------------------------------------------------------------- Income taxes per Consolidated Statements of Income $ 230.1 $ 186.4 $ 177.7 ============================================================================================================= Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends) $ 588.6 $ 526.3 $ 505.4 Statutory federal income tax rate 35% 35% 35% - ------------------------------------------------------------------------------------------------------------- Income taxes computed at statutory federal rate 206.0 184.2 176.9 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 12.6 15.3 13.6 Allowance for equity funds used during construction (0.9) (2.2) (2.2) Amortization of deferred investment tax credits (8.3) (8.6) (8.8) Tax credits flowed through to income (6.5) (3.2) (0.3) Amortization of deferred tax rate differential on regulated activities (2.9) (3.0) (2.3) State income taxes 34.0 8.9 9.8 Other (3.9) (5.0) (9.0) - ------------------------------------------------------------------------------------------------------------- Total income taxes $ 230.1 $ 186.4 $ 177.7 ============================================================================================================= Effective income tax rate 39.1% 35.4% 35.2% At December 31, 2000 1999 - ------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,121.1 $1,102.6 Income taxes recoverable through future rates 32.8 35.7 Deferred termination and postemployment costs 13.6 14.7 Deferred fuel costs 24.9 25.8 Leveraged leases 17.0 19.9 Energy trading activities 1,691.8 71.4 Deferred electric generation-related regulatory assets 93.7 100.3 Other 161.7 192.6 - ------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 3,156.6 1,563.0 - ------------------------------------------------------------------------------------------------------------- Deferred tax assets Accrued pension and postemployment benefit costs 76.5 63.6 Deferred investment tax credits 35.5 38.3 Nuclear decommissioning liability 28.2 25.4 Energy trading activities 1,510.6 15.1 Other 166.3 131.8 - ------------------------------------------------------------------------------------------------------------- Total deferred tax assets 1,817.1 274.2 - ------------------------------------------------------------------------------------------------------------- Deferred tax liability, net $1,339.5 $1,288.8 =============================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 52 CONSOLIDATED STATEMENTS OF INCOME Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Revenues Electric revenues $ 2,135.2 $2,259.5 $ 2,219.2 Gas revenues 611.6 485.3 449.4 Nonregulated revenues -- 347.4 717.8 - ------------------------------------------------------------------------------------------------------------------------------------ Total revenues 2,746.8 3,092.2 3,386.4 Expenses Operating Expenses: Electric fuel and purchased energy 870.5 486.8 505.7 Gas purchased for resale 350.7 233.7 208.6 Operations and maintenance 554.4 728.8 731.6 Nonregulated--selling, general, and administrative -- 286.0 607.1 Depreciation and amortization 367.9 427.9 375.5 Taxes other than income taxes 193.2 224.7 219.4 - ------------------------------------------------------------------------------------------------------------------------------------ Total operating expenses 2,336.7 2,387.9 2,647.9 - ------------------------------------------------------------------------------------------------------------------------------------ Income from Operations 410.1 704.3 738.5 Other Income 9.8 8.4 5.7 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Fixed Charges and Income Taxes 419.9 712.7 744.2 Fixed Charges Interest expense (net) 187.2 209.7 242.2 Allowance for borrowed funds used during construction (3.2) (3.8) (3.4) - ------------------------------------------------------------------------------------------------------------------------------------ Total fixed charges 184.0 205.9 238.8 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Income Taxes 235.9 506.8 505.4 Income Taxes Current 142.1 192.1 169.0 Deferred (44.4) (5.2) 17.5 Investment tax credit adjustments (5.3) (8.5) (8.8) - ------------------------------------------------------------------------------------------------------------------------------------ Total income taxes 92.4 178.4 177.7 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Extraordinary Item 143.5 328.4 327.7 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) -- (66.3) -- - ------------------------------------------------------------------------------------------------------------------------------------ Net Income 143.5 262.1 327.7 Preference Stock Dividends 13.2 13.5 21.8 - ------------------------------------------------------------------------------------------------------------------------------------ Earnings Applicable to Common Stock $ 130.3 $ 248.6 $ 305.9 ==================================================================================================================================== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) Net Income $ 143.5 $ 262.1 $ 327.7 Other comprehensive income/(loss), net of taxes -- (3.4) 1.2 - ------------------------------------------------------------------------------------------------------------------------------------ Comprehensive Income $ 143.5 $ 258.7 $ 328.9 ====================================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 53 CONSOLIDATED BALANCE SHEETS Baltimore Gas and Electric Company and Subsidiaries
At December 31, 2000 1999 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 21.3 $ 23.5 Accounts receivable (net of allowance for uncollectibles of $13.4 and $13.0 respectively) 413.0 311.6 Accounts receivable, affiliated companies 133.2 4.5 Note receivable, affiliated company 87.0 -- Fuel stocks 34.1 94.9 Materials and supplies 37.3 139.1 Prepaid taxes other than income taxes 44.9 72.4 Other 4.7 9.0 - ---------------------------------------------------------------------------------------------------------------------- Total current assets 775.5 655.0 - ---------------------------------------------------------------------------------------------------------------------- Investments and Other Assets Nuclear decommissioning trust fund -- 217.9 Net pension asset 100.2 99.8 Safe Harbor Water Power Corporation -- 34.5 Other 68.7 61.6 - ---------------------------------------------------------------------------------------------------------------------- Total investments and other assets 168.9 413.8 - ---------------------------------------------------------------------------------------------------------------------- Utility Plant Plant in service Electric 3,259.0 7,088.6 Gas 988.4 962.0 Common 532.9 569.5 - ---------------------------------------------------------------------------------------------------------------------- Total plant in service 4,780.3 8,620.1 Accumulated depreciation (1,700.3) (3,466.1) - ---------------------------------------------------------------------------------------------------------------------- Net plant in service 3,080.0 5,154.0 Construction work in progress 75.3 222.3 Nuclear fuel (net of amortization) -- 133.8 Plant held for future use 4.5 13.0 - ---------------------------------------------------------------------------------------------------------------------- Net utility plant 3,159.8 5,523.1 - ---------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 514.9 637.4 Other 35.1 43.3 - ---------------------------------------------------------------------------------------------------------------------- Total deferred charges 550.0 680.7 - ---------------------------------------------------------------------------------------------------------------------- Total Assets $ 4,654.2 $ 7,272.6 ======================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 54 CONSOLIDATED BALANCE SHEETS Baltimore Gas and Electric Company and Subsidiaries
At December 31, 2000 1999 - ---------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 32.1 $ 129.0 Current portions of long-term debt and preference stock 567.6 523.9 Accounts payable 119.3 218.1 Accounts payable, affiliated companies 103.5 4.7 Customer deposits 44.4 40.6 Accrued taxes 25.0 9.2 Accrued interest 43.4 48.2 Accrued vacation costs 20.8 35.7 Other 29.6 69.1 - ---------------------------------------------------------------------------------------------------------- Total current liabilities 985.7 1,078.5 - ---------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 508.7 1,032.0 Postretirement and postemployment benefits 231.2 231.0 Deferred investment tax credits 25.0 109.6 Decommissioning of federal uranium enrichment facilities 23.7 27.2 Other 23.2 42.9 - ---------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 811.8 1,442.7 - ---------------------------------------------------------------------------------------------------------- Long-term Debt First refunding mortgage bonds of BGE 1,174.7 1,321.7 Other long-term debt of BGE 976.6 1,135.8 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 34.0 33.0 Unamortized discount and premium (3.3) (10.6) Current portion of long-term debt (567.6) (523.9) - ---------------------------------------------------------------------------------------------------------- Total long-term debt 1,864.4 2,206.0 - ---------------------------------------------------------------------------------------------------------- Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 465.1 1,494.0 Retained earnings 337.2 861.4 - ---------------------------------------------------------------------------------------------------------- Total common shareholder's equity 802.3 2,355.4 - ---------------------------------------------------------------------------------------------------------- Total capitalization 2,856.7 4,751.4 - ---------------------------------------------------------------------------------------------------------- Commitments, Guarantees, and Contingencies (see Note 10) Total Liabilities and Capitalization $ 4,654.2 $ 7,272.6 ==========================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 55
CONSOLIDATED STATEMENTS OF CASH FLOWS Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 143.5 $ 262.1 $ 327.7 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss -- 66.3 -- Depreciation and amortization 393.6 480.4 427.8 Deferred income taxes (44.4) (5.2) 17.5 Investment tax credit adjustments (5.3) (8.5) (8.8) Deferred fuel costs 2.8 (61.1) (8.3) Accrued pension and postemployment benefits 23.1 35.5 41.6 Write-downs of real estate investments -- -- 23.7 Allowance for equity funds used during construction (2.6) (6.2) (6.3) Equity in earnings of affiliates and joint ventures (net) 1.3 29.1 (54.5) Changes in assets from energy trading activities -- (133.0) (123.6) Changes in liabilities from energy trading activities -- 99.0 90.4 Changes in other current assets (189.7) (15.1) 18.3 Changes in other current liabilities 68.7 22.7 77.0 Other 5.7 16.7 (1.7) - ------------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 396.7 782.7 820.8 - ------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (excluding AFC) (309.5) (385.7) (338.1) Nuclear fuel expenditures (39.5) (49.2) (50.5) Deferred conservation expenditures (0.6) (1.1) (16.2) Contributions to nuclear decommissioning trust fund (8.8) (17.6) (17.6) Purchases of marketable equity securities -- (9.2) (33.3) Sales of marketable equity securities -- 6.0 32.8 Power projects -- (17.9) (252.5) Other 0.7 14.0 (35.9) - ------------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (357.7) (460.7) (711.3) - ------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net (maturity) issuance of short-term borrowings (96.9) 129.0 (316.1) Proceeds from issuance of Long-term debt 377.3 257.2 831.3 Common stock -- 9.6 51.8 Reacquisition of long-term debt (121.7) (466.3) (355.2) Redemption of preference stock -- (7.0) (127.9) Common stock dividends paid -- (62.7) (246.0) Preferred and preference stock dividends paid (13.2) (13.6) (21.0) Distributions to Constellation Energy (188.5) (316.6) -- Other 1.8 (1.8) 84.7 - ------------------------------------------------------------------------------------------------------------------------------- Net cash used in financing activities (41.2) (472.2) (98.4) - ------------------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (2.2) (150.2) 11.1 Cash and Cash Equivalents at Beginning of Year 23.5 173.7 162.6 - ------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 21.3 $ 23.5 $ 173.7 =============================================================================================================================== Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 184.7 $ 200.2 $ 236.7 Income taxes $ 127.6 $ 178.8 $ 164.3
Noncash Investing and Financing Activities: On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of associated liabilities, to nonregulated affiliates of Constellation Energy pursuant to the Maryland PSC's Restructuring Order. In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62 million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COPT received 14 operating properties and two properties under development from CREG. See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 56 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 SIGNIFICANT ACCOUNTING POLICIES Nature of Our Business - ---------------------- Constellation Energy(R) Group, Inc. (Constellation Energy) is a diversified North American energy company. Constellation Energy conducts its business through various subsidiaries that primarily include a domestic merchant energy business and Baltimore Gas and Electric Company (BGE(R)). Our domestic merchant energy business is focused mostly on power marketing and merchant generation in North America. BGE is an electric and gas public utility distribution company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland. We describe our operating segments in Note 2. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. Reference in this report to the "utility business" is to BGE. On April 30, 1999, Constellation Energy became the holding company for BGE and Constellation(R) Enterprises, Inc. Constellation Enterprises was previously owned by BGE. BGE's outstanding common stock automatically became shares of common stock of Constellation Energy. BGE's debt securities, obligated mandatorily redeemable trust preferred securities, and preference stock remain securities of BGE, or its subsidiaries. Consolidation Policy - -------------------- We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method. Consolidation - ------------- We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate intercompany balances and transactions when we consolidate these accounts. This report is a combined report of Constellation Energy and BGE. The consolidated financial statements of Constellation Energy include the accounts of: . Constellation Energy, . BGE and its subsidiaries, . Constellation Enterprises, Inc. and its subsidiaries, and . Constellation Nuclear, LLC and its subsidiaries. The consolidated financial statements of BGE include the accounts of: . BGE . ComfortLink, and . BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. The Equity Method - ----------------- We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report: . our interest in the entity as an investment in our Consolidated Balance Sheets, and . our percentage share of the earnings from the entity in our Consolidated Statements of Income. The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation. The Cost Method - --------------- We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method. Regulation of Utility Business - ------------------------------ The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets and liabilities further in Note 5. In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. On November 10, 1999, the Maryland PSC issued a Restructuring Order that we believe provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises--Accounting for the Discontinuation of FASB Statement No. 71 and EITF No. 97-4 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated. We discuss this further in Note 4. 57 Revenues - -------- Nonregulated Businesses - ----------------------- We record nonregulated revenues in our Consolidated Statements of Income in the period earned for services rendered, commodities or products delivered, or contracts settled. Our subsidiary, Constellation Power Source, engages in power marketing activities, which include trading electricity, other energy commodities, and related derivatives (such as futures, forwards, options, and swaps). Constellation Power Source accounts for its activities using the mark-to-market method of accounting in accordance with EITF Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Under the mark-to-market method of accounting, we report: . commodity positions and derivatives at fair value as "Assets from energy trading activities" or "Liabilities from energy trading activities" in our Consolidated Balance Sheets, and . changes in fair value and net gains and losses from realized transactions as components of "Nonregulated revenues" in our Consolidated Statements of Income. Changes in fair value result primarily from new transactions and the impact of price and interest rate movements. Regulated Utility - ----------------- We record utility revenues when we provide service to customers. Fuel and Purchased Energy Costs - ------------------------------- We incur costs for: . the fuel we use to generate electricity, . purchases of electricity from others, and . natural gas that we resell. These costs are included in "Operating expenses" in our Consolidated Statements of Income. We discuss each of these separately below. Fuel Used to Generate Electricity and Purchases of Electricity From Others - -------------------------------------------------------------------------- Effective July 1, 2000, these costs are recorded as incurred. Historically and until July 1, 2000, we were allowed to recover our costs of electric fuel under the electric fuel rate clause set by the Maryland PSC. Under the electric fuel rate clause, we charged our electric customers for: . the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and . the net cost of purchases and sales of electricity. We charged the actual costs of these items to customers with no profit to us. To do this, we had to keep track of what we spent and what we collected from customers under the fuel rate in a given period. Usually these two amounts were not the same because there was a difference between the time we spent the money and the time we collected it from our customers. Under the electric fuel rate clause, we deferred (included as an asset or liability in our Consolidated Balance Sheets and excluded from our 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. We either billed or refunded our customers that difference in the future. As a result of the Restructuring Order, the fuel rate was discontinued effective July 1, 2000. We discuss this further in Note 5. Natural Gas - ----------- We charge our gas customers for the natural gas they purchase from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this note. However, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market based rates incentive mechanism. Under market based rates our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. Risk Management - --------------- We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. Our domestic merchant energy and regulated gas businesses use derivative instruments to manage changes in their respective commodity prices. We discuss our risk management activities in more detail below. Domestic Merchant Energy Business - --------------------------------- Our domestic merchant energy business is exposed to market risk from the power marketing operation of Constellation Power Source and from our electric generation operations. Constellation Power Source manages the market risk inherent in its power marketing activities on a portfolio basis, subject to established trading and risk management policies. Constellation Power Source uses a variety of derivative instruments, including: . forward contracts, which commit us to purchase or sell energy commodities in the future; . futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date; . swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) amount; and . option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price. 58 Market risk arises from the potential for changes in the value of energy commodities and related derivatives due to: changes in commodity prices, volatility of commodity prices, and fluctuations in interest rates. A number of factors associated with the structure and operation of the electricity market significantly influence the level and volatility of prices for energy commodities and related derivative products. These factors include: . seasonal changes in demand, . hourly fluctuations in demand due to weather conditions, . available supply resources, . transportation availability and reliability within and between regions, . procedures used to maintain the integrity of the physical electricity system during extreme conditions, and . changes in the nature and extent of federal and state regulations. These 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: . weather conditions, . market liquidity, . capability and reliability of the physical electricity and gas systems, and . the nature and extent of electricity deregulation. Our domestic merchant energy business conducts electric generation operations primarily through Constellation Power Source Generation, Calvert Cliffs, and Constellation Power. Presently, the majority of the generating capacity controlled by our domestic merchant energy business is used to provide standard offer service to BGE. However, beginning in July 2002, we expect approximately 1,000 megawatts of industrial customer load will leave standard offer service. The remainder of the standard offer service arrangement with BGE terminates on June 30, 2003. Additionally, we plan to expand our generation operations. As a result, our domestic merchant energy business has a substantial and increasing amount of generating capacity that is subject to future changes in wholesale electricity prices and has fuel requirements that are subject to future changes in coal, natural gas, and oil prices. Additionally, if one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed price sale commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices. Constellation Power Source manages the commodity price risk of our electric generation operations as part of its overall portfolio. Additionally, the domestic merchant energy business may enter into fixed-price contracts to hedge a portion of its exposure to future electricity and fuel commodity price risk. At December 31, 2000, our domestic merchant energy business has several contracts to sell electricity for each calendar year beginning 2003 through 2010 at fixed prices to hedge a portion of the forecasted sales of electricity by our domestic merchant energy plants during these periods. At December 31, 2000, we recorded deferred hedge losses of $58 million in "Other deferred charges" in our Consolidated Balance Sheets. We will reclassify these deferred hedge losses to "Accumulated other comprehensive income" when we adopt SFAS No. 133 in 2001. Regulated Electric Business - --------------------------- The standard offer service arrangement between BGE and Constellation Power Source ends June 30, 2003. Under the Restructuring Order, effective July 1, 2000, BGE's residential rates are frozen for a six-year period and its commercial and industrial rates are frozen for four to six years. As a result, BGE will be subject to commodity price risk beginning July 1, 2003 upon termination of the existing standard offer arrangement. In accordance with the Restructuring Order, BGE will competitively bid the standard offer service supply for the remaining period of the rate freeze subsequent to June 30, 2003. During the remaining period of BGE's rate freeze, BGE will be unable to pass through to its customers any increase in the market price of electricity it must purchase to meet the standard offer service load. Our regulated electric business is evaluating various alternatives to minimize the market risk after June 30, 2003. Regulated Gas Business - ---------------------- We use basis swaps in the winter months (November through March) to hedge our price risk associated with natural gas purchases under our market based rates incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps to hedge our price risk associated with our off-system gas sales. The fixed portion represents a specific dollar amount that we will pay or receive and the floating portion represents a fluctuating amount based on a published index that we will receive or pay. Our regulated gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. BGE's off-system gas sales activities represent trading activities under EITF 98-10. Accordingly, we use mark-to-market accounting to record these transactions. The trading activities relating to our off-system gas sales were not material at December 31, 2000 and 1999. We defer, as unrealized gains or losses, the changes in fair value of the swap agreements under the market based rates incentive mechanism and the customers' portion of off-system gas sales in our Consolidated Balance Sheets. When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off-system gas sales in earnings as a component of gas costs. 59 Credit Risk - ----------- We are exposed to credit risk, primarily through Constellation Power Source. Credit risk is the loss that may result from a counterparty's nonperformance. Constellation Power Source uses credit policies to control its credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements. However, due to the possibility of extreme volatility in the prices of electricity commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity Constellation Power Source had contracted for), Constellation Power Source could sustain a loss that could have a material impact on our financial results. Taxes - ----- We summarize our income taxes in our Consolidated Statements of Income Taxes. As you read this section, it may be helpful to refer to those statements. Income Tax Expense - ------------------ We have two categories of income taxes in our Consolidated Statements of Income- - -current and deferred. We describe each of these below. Our current income tax expense consists solely of regular tax less applicable tax credits. Our deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to common shareholders' equity. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this note) during the year. Investment Tax Credits - ---------------------- We have deferred the investment tax credit associated with our regulated utility business and assets previously held by our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated businesses, other than leveraged leases. Deferred Income Tax Assets and Liabilities - ------------------------------------------ We must report some of our revenues and expenses differently for our financial statements than we do for income tax purposes. The tax effects of the differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the assets and liabilities using income tax rates that are currently in effect. A portion of our total deferred income tax liability relates to our regulated utility business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 5. State and Local Taxes - --------------------- As discussed in Note 4, tax legislation has made comprehensive changes to the state and local taxation of electric and gas utilities. State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income. Through December 31, 1999, we paid Maryland public service company franchise tax on our utility revenue from sales in Maryland instead of state income tax. We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income. Cash and Cash Equivalents - ------------------------- For the purpose of reporting our cash flows, we define cash equivalents as highly liquid investments that mature in three months or less. At December 31, 2000, $112.5 million of the cash balance included in our Consolidated Balance Sheets was restricted under certain collateral arrangements for our power marketing operation. Inventory - --------- We report the majority of our fuel stocks and materials and supplies at average cost. Real Estate Projects and Investments - ------------------------------------ In Note 3, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments consist of: . land under development in the Baltimore-Washington corridor, . a mixed-use planned-unit development, and . an equity interest in Corporate Office Properties Trust, a real estate investment trust. The costs incurred to acquire and develop properties are included as part of the cost of the properties. Financial Investments and Trading Securities - -------------------------------------------- In Note 3, we summarize the financial investments that are in our Consolidated Balance Sheets. SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use specific identification to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available- for-sale securities, which we describe separately on the next page. We report investments that are not covered by SFAS No. 115 at their cost. 60 Trading Securities - ------------------ Our other nonregulated businesses classify some of their investments in marketable equity securities and financial limited partnerships as trading securities. We include any unrealized gains or losses on these securities in "Nonregulated revenues" in our Consolidated Statements of Income. Available-for-Sale Securities - ----------------------------- We classify our investments in the nuclear decommissioning trust fund as available-for-sale securities. We include any unrealized gains or losses on the trust assets as a change in the decommissioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading "Decommissioning Costs" later in this note. In addition, our other nonregulated businesses classify some of their investments in marketable equity securities as available-for-sale securities. We include any unrealized gains or losses on these securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and in the Consolidated Statements of Capitalization. Evaluation of Assets for Impairment and Other Than Temporary Decline in Value - ----------------------------------------------------------------------------- SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to Be Disposed Of, applies particular requirements to some of our assets that have long lives (some examples are generating property and equipment and real estate). We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We recognize an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset. Additionally, we evaluate our equity-method investments to determine whether our investments have a loss in value that is considered other than a temporary decline in value. We use our best estimates to determine if there has been an impairment or decline in value other than temporary and consider various factors including forward price curves for energy, fuel costs, and operating costs. However, it is possible that future market prices and project costs could vary from those used in evaluating our long-lived assets and investments, and the impact of such variations could be material. Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning - ------------------------------------------------------------------------------ We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 121. Our original costs include: . material and labor, . contractor costs, and . construction overhead costs and financing costs (where applicable). We charge retired or otherwise disposed of property, plant and equipment that was depreciated under the composite, straight-line method to accumulated depreciation. This includes regulated utility property, plant and equipment and nonregulated generating assets previously owned by the regulated utility. When any other property, plant and equipment is retired, or otherwise disposed of, we reduce the property, plant and equipment balances and related accumulated depreciation and amortization amounts, and recognize any gain or loss in our Consolidated Statements of Income. The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income as incurred. We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $143 million at December 31, 2000 and $156 million at December 31, 1999. The "Nonregulated generation property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $901.8 million at December 31, 2000 and $97.7 million at December 31, 1999. Depreciation Expense - -------------------- We compute depreciation over the estimated useful lives of depreciable property using the: . composite, straight-line rates (approved by the Maryland PSC for our regulated utility business) applied to the average investment in classes of depreciable property based on an average rate of approximately three percent per year, . units of production method for certain nonregulated generation facilities, or . straight-line method. Amortization Expense - -------------------- Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income. An amount is considered fully amortized when it has been reduced to zero. We are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The contributions are generally payable over 15 years with escalation for inflation and are based upon the proportionate amount of uranium enriched by the Department of Energy for each utility. We amortize the deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We also amortize nuclear fuel based on the energy produced over the life of the fuel including the quarterly fees we pay to the Department of Energy for the future disposal of spent nuclear fuel. These fees are based on the kilowatt- hours of electricity sold. We report the amortization expense for nuclear fuel in "Operating expenses" in our Consolidated Statements of Income. 61 Decommissioning Costs - --------------------- We must accumulate a reserve for the costs that we expect to incur in the future to decommission the radioactive portion of Calvert Cliffs. We do this based on a sinking fund methodology. The Maryland PSC authorized us to include in the rates that we charge our customers decommissioning expense based on a facility- specific cost estimate so we can accumulate a decommissioning reserve of $521 million in 1993 dollars by the end of Calvert Cliffs' service life, adjusted to reflect expected inflation. We have reported the decommissioning reserve in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $310.1 million at December 31, 2000 and $287.5 million at December 31, 1999. Our contributions to the nuclear decommissioning trust funds were $13.2 million for 2000 and $17.6 million for 1999 and 1998. To fund the costs we expect to incur to decommission the plant, we established an external decommissioning trust in accordance with Nuclear Regulatory Commission (NRC) regulations. We report the assets in the trust in "Nuclear decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate. We use the facility-specific cost estimate for funding these costs and providing the required financial assurance. Capitalized Interest and Allowance for Funds Used During Construction - --------------------------------------------------------------------- Capitalized Interest - -------------------- With the issuance of the Restructuring Order, we ceased accruing AFC (discussed below) for electric generation-related construction projects. Our nonregulated businesses capitalize interest costs under SFAS No. 34, Capitalizing Interest Costs, for costs incurred to finance our power projects and real estate developed for internal use. Allowance for Funds Used During Construction (AFC) - -------------------------------------------------- We finance regulated utility construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility property is placed in service. The AFC rates are 9.40% for electric plant, 8.61% for gas plant, and 9.19% for common plant. We compound AFC annually. Long-Term Debt - -------------- We defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, and other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs over the life of the debt. When we incur gains or losses on debt that we retire prior to maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. When we incur gains or losses on debt that we retire prior to maturity in our nonregulated businesses, we record these gains or losses as an extraordinary item, if material. Use of Accounting Estimates - --------------------------- Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including: . our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, . our disclosure of contingent assets and liabilities at the dates of the financial statements, and . our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates. 62 Reclassifications - ----------------- We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. Accounting Standards Issued - --------------------------- In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 establishes the accounting and disclosure standards for derivative financial instruments and hedging activities. In July 1999, the FASB issued SFAS No. 137 that delayed the effective date for SFAS No. 133 by one year. Therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31, 2001. In June 2000, the FASB issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, that amended certain provisions of SFAS No. 133 and addressed a limited number of implementation issues related to SFAS No. 133. These statements require that we recognize all derivatives on the balance sheet at fair value. Changes in the value of derivatives that are not hedges must be recorded in earnings. We expect to use derivatives to hedge the risk of variations in future cash flows from forecasted purchases and sales of electricity. Changes in the value of these derivatives will be recognized in other comprehensive income until the forecasted transaction occurs. The ineffective portion of the change in fair value of a derivative being used as a hedge will be immediately recognized in earnings. The cumulative effect on earnings of adopting these statements is not material for Constellation Energy. As of December 31, 2000, we entered into certain forward sales of electricity that were designated as cash flow hedges of forecasted transactions. We will record a reduction in other comprehensive income of approximately $35 million after-tax to reflect these cash flow hedges in accordance with these statements. The cumulative effect of adopting these statements is not material for BGE. 2 INFORMATION BY OPERATING SEGMENT In 1999, we reported three operating business segments--Electric, Gas, and Energy Services. In response to the deregulation of electric generation, we realigned our organization and combined our wholesale power marketing operation with our domestic plant development and operation activities to form a domestic merchant energy business. In 2000, we revised our operating segments to reflect the realignments of our organization. Our new reportable operating segments are--Domestic Merchant Energy, Regulated Electric, and Regulated Gas: . Our nonregulated domestic merchant energy business: . provides power marketing and risk management services, . develops, owns, and operates domestic power projects, and . provides nuclear consulting services. . Our regulated electric business purchases, distributes and sells electricity, and . Our regulated gas business purchases, transports, and sells natural gas. We have restated certain prior period information for comparative purposes based on our new reportable operating segments. Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the domestic merchant energy business segment. Prior to that date, the financial results of electric generation are included in our regulated electric business. Our remaining nonregulated businesses: . develop, own, and operate international power projects in Latin America, . provide energy products and services, . sell and service electric and gas appliances, and heating and air conditioning systems, engage in home improvements, and sell natural gas through mass marketing efforts, . provide cooling services, . engage in financial investments, and . develop, own and manage real estate and senior-living facilities. These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown on the next page. 63
Domestic Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------ (In millions) 2000 Unaffiliated revenues $ 415.4 $2,134.7 $ 603.8 $ 724.6 $ -- $ 3,878.5 Intersegment revenues 576.6 0.5 7.8 15.7 (600.6) -- - ------------------------------------------------------------------------------------------------------------------------ Total revenues 992.0 2,135.2 611.6 740.3 (600.6) 3,878.5 Depreciation and amortization 80.9 319.9 46.2 23.0 -- 470.0 Equity in income of equity- method investees (a) -- 2.4 -- -- -- 2.4 Net interest expense 31.0 157.0 25.5 53.1 (8.4) 258.2 Income tax expense 122.5 72.2 21.9 13.5 -- 230.1 Net income (b) 206.8 102.3 30.6 5.6 -- 345.3 Segment assets 6,753.3 3,453.4 1,028.8 1,299.5 (150.4) 12,384.6 Capital expenditures 811.2 290.3 59.7 19.3 -- 1,180.5 1999 Unaffiliated revenues $ 212.9 $2,258.8 $ 476.5 $ 838.0 $ -- $ 3,786.2 Intersegment revenues -- 1.2 11.6 20.1 (32.9) -- - ------------------------------------------------------------------------------------------------------------------------ Total revenues 212.9 2,260.0 488.1 858.1 (32.9) 3,786.2 Depreciation and amortization 5.0 376.4 44.9 23.5 -- 449.8 Equity in income of equity- method investees (a) -- 5.1 -- -- -- 5.1 Net interest expense -- 162.4 24.4 56.1 (1.4) 241.5 Income tax expense (benefit) 29.4 149.2 18.1 (10.3) -- 186.4 Extraordinary loss -- 66.3 -- -- -- 66.3 Net income (loss) (c) 52.4 198.8 33.0 (24.1) -- 260.1 Segment assets 1,206.1 6,312.6 915.3 1,231.3 18.5 9,683.8 Capital expenditures 260.9 366.8 69.2 17.3 -- 714.2 1998 Unaffiliated revenues $ 147.3 $2,219.2 $ 449.4 $ 570.5 $ -- $ 3,386.4 Intersegment revenues -- 1.6 1.7 12.5 (15.8) -- - ------------------------------------------------------------------------------------------------------------------------ Total revenues 147.3 2,220.8 451.1 583.0 (15.8) 3,386.4 Depreciation and amortization 3.0 313.0 45.4 13.9 0.2 375.5 Equity in income of equity- method investees (a) -- 5.0 -- -- -- 5.0 Net interest expense -- 164.9 23.6 50.7 (0.4) 238.8 Income tax expense (benefit) 28.6 146.6 13.4 (10.9) -- 177.7 Net income (loss) (d) 53.1 259.6 26.1 (32.9) -- 305.9 Segment assets 885.3 6,342.8 934.6 1,275.2 (3.8) 9,434.1 Capital expenditures 317.5 339.5 65.5 7.7 -- 730.2
(a) Our domestic merchant energy business records its equity in the income of equity method investees in unaffiliated revenues. (b) Our regulated electric business recorded expense of $4.2 million related to employees that elected to participate in a Targeted Voluntary Special Early Retirement Program. In addition, our domestic merchant energy business recorded a $15.0 million deregulation transition cost incurred by our power marketing operation. (c) Our regulated electric business recorded expense of $4.9 million related to Hurricane Floyd. Our domestic merchant energy business recorded $14.2 million for the write-off of two geothermal power plants. Our Latin American operation recorded $4.5 million for the write-down to reflect the fair value of our investment in a power project in Bolivia. Our financial investments operation recorded $16.0 million for the write-down of its investment in Capital Re stock to reflect the market value of this investment. Our real estate and senior- living facilities operation recorded $5.8 million for the write-down of certain senior-living facilities. (d) Our domestic merchant energy business recorded $10.4 million for its share of earnings in a partnership. Our energy products and services operation recorded $5.5 million for the write-off of an energy services investment. Our real estate and senior-living facilities operation recorded $15.4 million for the write-down of a real estate project. 64 3 INVESTMENTS Real Estate Projects and Investments - ------------------------------------ Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following:
At December 31, 2000 1999 - ---------------------------------------------------- (In millions) Properties under development $165.1 $197.8 Rental and operating properties (net of accumulated depreciation) 12.7 9.2 Equity interest in real estate investments 112.5 103.1 - ---------------------------------------------------- Total real estate projects and investments $290.3 $310.1 ====================================================
In 1999, CREG sold Church Street Station--an entertainment, dining, and retail complex in Orlando, Florida--for $11.5 million, the approximate book value of the complex. In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust based in Philadelphia, under which COPT assumed approximately $62 million of CREG's outstanding debt, paid CREG approximately $22.8 million in cash, and issued to CREG approximately 7.0 million common shares representing a 41.9% equity interest in COPT and 985,000 convertible preferred shares. Each convertible preferred share yields 5.5% per year, and is convertible after two years into 1.8748 common shares. In exchange, COPT received 14 operating properties and two properties under development from CREG as well as certain other assets, options, and first refusal rights. These options and first refusal rights are related to approximately 91 acres of identified properties which are adjacent to operating properties acquired by COPT. At December 31, 2000, 30 acres remain under these options and first refusal rights with terms that range from one to three years. In September 2000, CREG converted 984,307 preferred shares of COPT into approximately 1.8 million common shares of COPT. Power Projects - -------------- Investments in power projects held by our domestic merchant energy business consist of the following:
At December 31, 2000 1999 - -------------------------------------------------- (In millions) East $ 86.3 $ 85.1 West 419.8 416.5 - -------------------------------------------------- Total domestic power projects $506.1 $501.6 ==================================================
Our Domestic-West power projects include investments of $297.9 million in 2000 and $301.8 million in 1999 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 10. In 1999, our domestic generation operation recorded a $14.2 million after-tax write-off of two geothermal power projects. These write-offs occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the inability to restructure certain project agreements. For the second project, the water temperature of the geothermal resource used by one of the plants for production declined. In 1998, our domestic generation operation recorded $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract. Our Latin American operation held power projects of $11.4 million at December 31, 2000 and $12.3 million at December 31, 1999. In 1999, our Latin American operation recorded a $4.5 million after-tax write-down to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy. Financial Investments - --------------------- Financial investments held by Constellation Investments, Inc. consist of the following:
At December 31, 2000 1999 - --------------------------------------------------- (In millions) Marketable equity securities $105.9 $ 84.2 Financial limited partnerships 32.7 35.8 Leveraged leases 22.4 25.4 - --------------------------------------------------- Total financial investments $161.0 $145.4 ===================================================
In 1999, our financial investments operation announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE), another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. As a result, our financial investments operation wrote-down its $94.2 million investment in Capital Re stock by $16.0 million after-tax to reflect the closing price of the business combination. Investments Classified as Available-for-Sale - -------------------------------------------- We classify our investments in the nuclear decommissioning trust fund as available-for-sale. In addition, we classify some of our other nonregulated businesses' marketable equity securities (shown above) as available-for-sale. This means we do not expect to hold them to maturity and we do not consider them trading securities. We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, in the following tables. 65
Amortized Unrealized Unrealized Fair At December 31, 2000 Cost Basis Gains Losses Value - ------------------------------------------------------------------------- (In millions) Marketable equity securities $171.8 $68.9 $(2.2) $238.5 Corporate debt and U.S. Government agency 26.1 0.1 (0.1) 26.1 State municipal bonds 61.3 2.3 (0.4) 63.2 - ------------------------------------------------------------------------- Totals $259.2 $71.3 $(2.7) $327.8 =========================================================================
Amortized Unrealized Unrealized Fair At December 31, 1999 Cost Basis Gains Losses Value - ------------------------------------------------------------------------- (In millions) Marketable equity securities $167.1 $42.8 $(2.1) $207.8 Corporate debt and U.S. Government agency 14.4 -- -- 14.4 State municipal bonds 74.2 -- (0.8) 73.4 - ------------------------------------------------------------------------- Totals $255.7 $42.8 $(2.9) $295.6 =========================================================================
The preceding tables include $34.7 million in 2000 and $40.5 million in 1999 of unrealized net gains associated with the nuclear decommissioning trust fund which are reflected as a change in the nuclear decommissioning trust fund on the Consolidated Balance Sheets. Gross and net realized gains and losses on available-for-sale securities were as follows:
2000 1999 1998 - ------------------------------------------------------------------------- (In millions) Gross realized gains $54.5 $ 11.7 $ 4.2 Gross realized losses (8.0) (38.8) (0.7) - ------------------------------------------------------------------------- Net realized gains (losses) $46.5 $(27.1) $ 3.5 =========================================================================
The Corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:
At December 31, 2000 Amount - --------------------------------------------------------- (In millions) Less than 1 year $ 0.9 1-5 years 41.9 5-10 years 23.7 More than 10 years 22.8 - --------------------------------------------------------- Total maturities of debt securities $89.3 =========================================================
4 RATE MATTERS AND ACCOUNTING IMPACTS OF DEREGULATION On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Effective January 1, 2000, the Maryland public service franchise tax was altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise tax on electric and natural gas utilities continues to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results are subject to the Maryland corporate income tax. Beginning July 1, 2000, the tax legislation also provides for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are: . All customers, except a few commercial and industrial companies that have signed contracts with BGE, can choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. . BGE's electric base rates were frozen through June 30, 2000. . BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006. . Commercial and industrial customers have up to four service options that will fix electric energy rates and transition charges for a period that generally ranges from four to six years. . BGE's electric fuel rate clause was discontinued effective July 1, 2000. . Electric delivery service rates are frozen for a four-year period 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. 66 . BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer. . Generation-related regulatory assets and nuclear decommissioning costs are included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their amortization schedules prior to July 1, 2000. . Effective July 1, 2000, BGE unbundled rates to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes. . Effective July 1, 2000, BGE transferred, at book value, its ten Maryland- based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. . BGE reduced its generation assets by $150 million pre-tax during the period July 1, 1999-June 30, 2000 to mitigate a portion of BGE's potentially stranded investments. . Universal service is being provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually. As discussed in Note 1, EITF 97-4 requires that a company should cease applying SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business. SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities. The Restructuring Order provided for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business. We discuss this further in Note 5. Pursuant to SFAS No. 101, the book value of property, plant, and equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process we used in evaluating and measuring impairment under the provisions of SFAS No. 121 involved two steps. First, we compared the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant was considered impaired when its undiscounted future net operating cash flows were less than its net book value. Second, we computed the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment. To the extent that the net book value of each impaired electric generation plant exceeded its fair value, we recorded a write-down. Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with BGE's Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher than its estimated fair value. However, Calvert Cliffs was not considered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceeded its book value. Accordingly, BGE did not record any impairment write-down related to Calvert Cliffs. However, we recognized after-tax impairment losses totaling $115.8 million associated with certain of our fossil plants under the provisions of SFAS No. 121. BGE had contracts to purchase electric capacity and energy that became uneconomic upon the deregulation of electric generation. Therefore, we recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts. In addition, BGE had deferred certain energy conservation expenditures that would not be recovered through its transmission and distribution business under the Restructuring Order. Accordingly, we recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures. At December 31, 1999, the total charge for BGE's electric generating plants that were impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately $160.3 million after-tax. BGE recorded approximately $94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately $56.0 million of associated deferred income taxes. The regulatory asset was amortized as it was recovered from ratepayers through June 30, 2000. This accomplished the $150 million reduction of its generation plants required by the Restructuring Order. We recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that was not recovered under the Restructuring Order. 67 5 REGULATORY ASSETS (NET) As discussed in Note 1, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers. We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.
At December 31, 2000 1999 - ------------------------------------------------------- (In millions) Generation plant reduction recoverable in current rates $ -- $ 75.0 Electric generation-related regulatory asset 267.8 286.6 Income taxes recoverable through future rates (net) 101.2 110.4 Deferred postretirement and postemployment benefit costs 38.7 41.9 Deferred conservation expenditures 5.8 12.9 Deferred environmental costs 28.8 31.3 Deferred fuel costs (net) 71.1 73.8 Other (net) 1.5 5.5 - ------------------------------------------------------- Total regulatory assets (net) $514.9 $637.4 =======================================================
Generation Plant Reduction Recoverable in Current Rates - ------------------------------------------------------- Under the Restructuring Order, BGE recorded a reduction to its generation plant of $150 million which it recovered through its rates between July 1, 1999 and June 30, 2000. In 1999, BGE recorded a $150 million regulatory asset for the required generation plant reduction that was amortized as it was recovered from ratepayers through June 30, 2000. Electric Generation-Related Regulatory Asset - -------------------------------------------- With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business. In accordance with SFAS No. 101 and EITF 97-4, all individual generation-related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business. Pursuant to the Restructuring Order, BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, new generation-related regulatory asset for amounts to be collected through its regulated transmission and distribution business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. Income Taxes Recoverable Through Future Rates (net) - --------------------------------------------------- As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse. In 1999, we reclassified the electric generation-related portion of this net regulatory asset to the electric generation-related regulatory asset discussed earlier in this note. Deferred Postretirement and Postemployment Benefit Costs - -------------------------------------------------------- Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 6. In 1999, we reclassified the electric generation-related portion of this regulatory asset to the electric generation-related regulatory asset discussed earlier in this note. Deferred Conservation Expenditures - ---------------------------------- Deferred conservation expenditures include two components: . operations costs (labor, materials, and indirect costs) associated with conservation programs approved by the Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's orders, and . revenues we collected from customers in 1996 in excess of our profit limit under the conservation surcharge. In 1999, we wrote off a portion of the unamortized electric conservation expenditures that will not be recovered under the Restructuring Order as discussed in Note 4. Deferred Environmental Costs - ---------------------------- Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 10. We are amortizing $21.6 million of these costs (the amount we had incurred through October 1995) and $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with Maryland PSC's orders. 68 Deferred Fuel Costs - ------------------- As described in Note 1, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas, and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers. We show our deferred fuel costs in the following table.
At December 31, 2000 1999 - -------------------------------------------- (In millions) Electric $42.3 $60.0 Gas 28.8 13.8 - -------------------------------------------- Deferred fuel costs (net) $71.1 $73.8 ============================================
Under the terms of the Restructuring Order, BGE's electric fuel rate clause was discontinued effective July 1, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. 6 PENSION, POSTRETIREMENT, OTHER POSTEMPLOYMENT, AND EMPLOYEE SAVINGS PLAN BENEFITS We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below. Pension Benefits - ---------------- We sponsor several defined benefit pension plans for our employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Our employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay. Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees. We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2000 were mostly marketable equity and fixed income securities, and group annuity contracts. In 1999, our Board of Directors approved the following amendments: . eligible participants were allowed to choose between an enhanced version of the current benefit formula and a new pension equity plan (PEP) formula. Pension benefits for eligible employees hired after December 31, 1999 are based on a PEP formula, and . pension and survivor benefits were increased for participants who retired prior to January 1, 1994 and for their surviving spouses. The financial impacts of the amendments are included in the tables beginning on the next page. Also during 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elected to retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6 million for pension and $2.4 million for postretirement benefit costs) for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. We will amortize this regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC gas base rate order. The remaining $7.0 million related to BGE's electric business was charged to expense. The TVSERP charges are not included in the tables of net periodic pension and postretirement benefit costs included in this section. Postretirement Benefits - ----------------------- We sponsor defined benefit postretirement health care and life insurance plans which cover nearly all BGE employees and certain employees of our subsidiaries. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused: . a transition obligation, which we are amortizing over 20 years, and . an increase in annual postretirement benefit costs. For our nonregulated businesses, we expense all postretirement benefit costs. For our regulated utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders: . in an April 1993 rate order, the Maryland PSC allowed us to expense one- half and defer, as a regulatory asset (see Note 5), the other half of the increase in annual postretirement benefit costs related to our regulated electric and gas businesses, and 69 . in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our regulated gas business. Beginning in 1998, the Maryland PSC authorized us to: . expense all of the increase in annual postretirement benefit costs related to our regulated electric business, and . amortize the regulatory asset for postretirement benefit costs related to our regulated electric and gas businesses over 15 years. Obligations, Assets, and Funded Status - -------------------------------------- We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans in the following tables:
Pension Postretirement Benefits Benefits 2000 1999 2000 1999 - ---------------------------------------------------------------------------- (In millions) Change in benefit obligation Benefit obligation at January 1 $1,016.7 $1,031.3 $358.7 $383.1 Service cost 25.4 26.1 7.7 8.6 Interest cost 73.1 65.3 26.6 24.4 Plan participants' contributions -- -- 2.8 2.0 Actuarial (gain) loss 0.8 (93.0) 40.9 (34.2) Plan amendments 6.7 44.6 (41.1) (5.0) TVSERP charge 7.6 -- 2.4 -- Benefits paid (85.2) (57.6) (22.1) (20.2) - ---------------------------------------------------------------------------- Benefit obligation at December 31 $1,045.1 $1,016.7 $375.9 $358.7 ============================================================================
Pension Postretirement Benefits Benefits 2000 1999 2000 1999 - ---------------------------------------------------------------------------- (In millions) Change in plan assets Fair value of plan assets at January 1 $1,084.9 $ 985.5 $ -- $ -- Actual return on plan assets 3.7 139.4 -- -- Employer contribution 26.7 17.6 19.3 18.2 Plan participants' contributions -- -- 2.8 2.0 Benefits paid (85.2) (57.6) (22.1) (20.2) - ---------------------------------------------------------------------------- Fair value of plan assets at December 31 $1,030.1 $1,084.9 $ -- $ -- ============================================================================
Pension Postretirement Benefits Benefits 2000 1999 2000 1999 - ----------------------------------------------------------------------------- (In millions) Funded Status Funded Status at December 31 $(15.0) $ 68.2 $(375.9) $(358.7) Unrecognized net actuarial (gain) loss 49.2 (27.2) 61.4 23.6 Unrecognized prior service cost 59.2 59.0 (0.4) (0.1) Unrecognized transition obligation -- -- 94.8 143.4 Unamortized net asset from adoption of SFAS No. 87 (0.2) (0.5) -- -- - ----------------------------------------------------------------------------- Prepaid (accrued) benefit cost $ 93.2 $ 99.5 $(220.1) $(191.8) =============================================================================
Net Periodic Benefit Cost - ------------------------- We show the components of net periodic pension benefit cost in the following table:
Year Ended December 31, 2000 1999 1998 - --------------------------------------------------------------------------------------------- (In millions) Components of net periodic pension benefit cost Service cost $ 25.4 $ 26.1 $ 21.6 Interest cost 73.1 65.3 63.0 Expected return on plan assets (83.6) (76.6) (72.1) Amortization of transition obligation (0.2) (0.2) (0.2) Amortization of prior service cost 6.5 2.5 2.5 Recognized net actuarial loss 2.6 10.1 5.6 Amount capitalized as construction cost (3.4) (4.2) (3.8) - --------------------------------------------------------------------------------------------- Net periodic pension benefit cost $ 20.4 $ 23.0 $ 16.6 =============================================================================================
We show the components of net periodic postretirement benefit cost in the following table:
Year Ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------- (In millions) Components of net periodic postretirement benefit cost Service cost $ 7.7 $ 8.6 $ 6.6 Interest cost 26.6 24.4 23.4 Amortization of transition obligation 7.9 11.0 11.4 Recognized net actuarial loss 3.1 1.9 0.2 Amount capitalized as construction cost (10.8) (9.4) (8.1) - ------------------------------------------------------------------------------------------- Net periodic postretirement benefit cost $ 34.5 $ 36.5 $ 33.5 ===========================================================================================
70 Assumptions - ----------- We made the assumptions below to calculate our pension and postretirement benefit obligations.
Pension Postretirement Benefits Benefits At December 31, 2000 1999 2000 1999 - ---------------------------------------------------------- Discount rate 7.50% 7.25% 7.50% 7.25% Expected return on plan assets 9.00 9.00 N/A N/A Rate of compensation increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be: . in 2000, 10.7% for Medicare-eligible retirees and 12.3% for retirees not covered by Medicare, and . in 2001, 6.5% for Medicare-eligible retirees and 8.0% for retirees not covered by Medicare. After 2001, we assumed both inflation rates will decrease by 0.5% annually to a rate of 5.5% in the years 2003 and 2006, respectively. After these dates, the inflation rate will remain at 5.5%. A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $51.7 million as of December 31, 2000 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.5 million annually. A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $41.5 million as of December 31, 2000 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.4 million annually. Other Postemployment Benefits - ----------------------------- We provide the following postemployment benefits: . health and life insurance benefits to our employees and certain employees of our subsidiaries who are found to be disabled under our Disability Insurance Plan, and . income replacement payments for employees found to be disabled before November 1995 (payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees). The liability for these benefits totaled $46.7 million as of December 31, 2000 and $46.5 million as of December 31, 1999. Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 5), the postemployment benefit liability attributable to our regulated utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note). We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our regulated electric and gas base rates to recover the higher costs in 1998. We assumed the discount rate for other postemployment benefits to be 5.5% in 2000 and 1999. Employee Savings Plan Benefits - ------------------------------ We also sponsor a defined contribution savings plan that is offered to all eligible employees of Constellation Energy and certain employees of our subsidiaries. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Under this plan, we make matching contributions to participant accounts. We made matching contributions to this plan of: . $10.8 million in 2000, . $10.4 million in 1999, and . $10.1 million in 1998. 7 SHORT-TERM BORROWINGS Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates. Constellation Energy - -------------------- Constellation Energy had commercial paper outstanding of $198.7 million at December 31, 2000 and $242.5 million at December 31, 1999. Constellation Energy had unused committed bank lines of credit of $565.0 million at December 31, 2000 and $295.0 million at December 31, 1999 for short- term financial needs, including letters of credit. These agreements also support Constellation Energy's commercial paper program. Letters of credit issued under these facilities totaled $180.3 million at December 31, 2000 and $23.1 million at December 31, 1999. In addition, Constellation Energy had $116.9 million in letters of credit outstanding at December 31, 2000 that were issued under separate credit facilities. The weighted-average effective interest rate for Constellation Energy's commercial paper were 6.31% for the year ended December 31, 2000 and 5.68% for 1999. BGE - --- BGE had commercial paper outstanding of $32.1 million at December 31, 2000 and $129.0 million at December 31, 1999. At December 31, 2000, BGE had unused committed bank lines of credit totaling $218.0 million supporting the commercial paper program compared to $183.0 million at December 31, 1999. The weighted-average effective interest rates for BGE's commercial paper were 6.36% for the year ended December 31, 2000 and 5.25% for 1999. Other Nonregulated Businesses - ----------------------------- Our other nonregulated businesses had short-term borrowings outstanding of $12.8 million at December 31, 2000. The weighted-average effective interest rate for our other nonregulated businesses' short-term borrowings was 8.59% for the year ended December 31, 2000. 71 8 LONG-TERM DEBT Long-term debt matures in one year or more from the date of issuance. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements. Constellation Energy - -------------------- In 2000, Constellation Energy issued $1.0 billion in long-term debt. On April 4, 2000, we issued $300.0 million of 7 7/8% Fixed Rate Notes, due April 1, 2005 and $200.0 million of Floating Rate Notes, due April 4, 2003. Interest on the floating rate notes is reset quarterly. On June 21, 2000, we issued $300.0 million of Extendible Notes, due June 21, 2010. The interest rate on these notes resets quarterly. On June 21, 2001, the notes may be remarketed for an additional period or redeemed for a purchase price equal to 100% of their principal amount, plus accrued interest. On October 19, 2000, we issued $200.0 million of Floating Rate Reset Notes, due March 15, 2002. We redeemed these notes on January 17, 2001 at par. On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable Floating Rate Notes, due January 17, 2002. These notes are mandatorily redeemable at a purchase price equal to 100% of their principal amount, plus accrued interest, at least five days prior to the separation of our domestic merchant energy business from our remaining businesses. In connection with the initiative to separate our businesses, Constellation Energy expects to redeem all of its outstanding debt at or prior to the separation. The redemption will occur through a combination of open market purchases, tender offers, and redemption calls. We expect to fund this redemption with short-term debt or other credit facilities, and to refinance this debt longer term after the separation. BGE - --- BGE's First Refunding Mortgage Bonds - ------------------------------------ BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets, including all utility properties and franchises and its subsidiary capital stock. Capital stock pledged under the mortgage is that of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage. BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption: . 8 3/8% Series, due 2001 . 5 1/2% Series, due 2004 . 7 1/4% Series, due 2002 . 7 1/2% Series, due 2007 . 6 1/2% Series, due 2003 . 6 5/8% Series, due 2008 . 6 1/8% Series, due 2003 Holders of the Remarketed Floating Rate Series due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1. BGE's Other Long-Term Debt - -------------------------- On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our domestic merchant energy business related to the transferred assets. At December 31, 2000, BGE remains contingently liable for this debt. On October 19, 2000, BGE issued $200.0 million of Floating Rate Reset Notes, due October 19, 2001. BGE can redeem these notes at 100% of the principal amount. On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option for the underwriters to remarket the ROARS on December 15, 2002. If the underwriters do not elect to remarket the ROARS on that date, then BGE must redeem the ROARS at 100% of the principal amount on December 15, 2002. We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2000 in the following table.
Weighted-Average Maturity Series Interest Rate Date - ----------------------------------------- B 8.77% 2002-2006 C 7.97 2003 D 6.66 2001-2006 E 6.66 2006-2012 G 6.08 2002-2008
Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options.
Series E Notes Principal Put Option Dates - -------------------------------------------------- (In millions) 6.75%, due 2012 $60.0 June 2002 and 2007 6.75%, due 2012 $25.0 June 2004 and 2007 6.73%, due 2012 $25.0 June 2004 and 2007
BGE has a $25 million revolving credit agreement that is available through 2003. At December 31, 2000 and 1999, BGE did not have any borrowings under revolving credit agreements. The bank charges us commitment fees based on the daily average of the unborrowed amount, and we pay market interest rates on any borrowings. This agreement also supports BGE's commercial paper program, as described in Note 7. 72 BGE Obligated Mandatorily Redeemable Trust Preferred Securities - --------------------------------------------------------------- On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%. The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur. The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest expense (net)" in the Consolidated Statements of Income and is deductible for income tax purposes. BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement. The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power. For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock. Other Nonregulated Businesses - ----------------------------- Revolving Credit Agreement - -------------------------- ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2001. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. Under this agreement, ComfortLink had outstanding $34 million at December 31, 2000 and $33 million at December 31, 1999. Mortgage and Construction Loans - ------------------------------- Our nonregulated businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments: . 8.00%, due in 2001 . 9.65%, due in 2028 . 4.25%, due in 2009 . 8.00%, due in 2033 The variable rate mortgage notes and construction loans require periodic payment of principal and interest. Unsecured Notes - --------------- The unsecured notes mature on the following schedule: Amount - ---------------------------------------------------------------- (In millions) 7.66%, due May 5, 2001 $135.0 5.67%, due May 5, 2001 152.0 - ---------------------------------------------------------------- Total unsecured notes at December 31, 2000 $287.0 ================================================================ Maturities of Long-Term Debt - ---------------------------- All of our long-term borrowings mature on the following schedule (includes sinking fund requirements): Constellation Nonregulated Year Energy Businesses BGE - -------------------------------------------------------------------------------- (In millions) 2001 $ -- $318.9 $ 481.2 2002 200.0 15.3 319.8 2003 200.0 0.8 285.7 2004 -- 8.3 155.3 2005 300.0 6.1 46.9 Thereafter 300.0 320.6 1,112.4 - -------------------------------------------------------------------------------- Total long-term debt at December 31, 2000 $1,000.0 $670.0 $2,401.3 ================================================================================ At December 31, 2000, BGE had long-term loans totaling $221.5 million that mature after 2002 (including $110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") that lenders could potentially require us to repay early. Of this amount, $111.5 million could be repaid in 2001, $60.0 million in 2002, and $50.0 million thereafter. At December 31, 2000, $86.5 million is classified as current portion of long-term debt as a result of these provisions. At December 31, 2000, our nonregulated businesses had long-term loans totaling $20.0 million that mature after 2002 that lenders could potentially require us to repay early. This amount is classified as current portion of long-term debt as a result of these repayment provisions. Weighted-Average Interest Rates for Variable Rate Debt - ------------------------------------------------------ Our weighted-average interest rates for variable rate debt were: Year ended December 31, 2000 1999 - ---------------------------------------------------------- Nonregulated Businesses (including Constellation Energy) Floating rate notes 6.98% --% Loans under credit agreement 6.64 5.68 Mortgage and construction loans 7.78 6.65 Tax-exempt debt transferred from BGE 4.26 -- BGE Remarketed floating rate series mortgage bonds 6.59% 5.19% Floating rate series mortgage bonds -- 5.41 Floating rate reset notes 7.27 -- Medium-term notes, Series G 6.58 5.38 Medium-term notes, Series H 6.58 5.64 Pollution control loan -- 3.22 Port facilities loan -- 3.24 Adjustable rate pollution control loan -- 3.59 Economic development plan -- 3.26 Variable rate pollution control plan -- 3.30 73 9 LEASES There are two types of leases--operating and capital. Capital leases qualify as sales or purchases of property and are reported in the Consolidated Balance Sheets. Capital leases are not material in amount. All other leases are operating leases and are reported in the Consolidated Statements of Income. We present information about our operating leases below. Outgoing Lease Payments - ----------------------- We, as lessee, lease some facilities and equipment used in our businesses. The lease agreements expire on various dates and have various renewal options. We expense all lease payments associated with our regulated utility operations. Lease expense was: . $11.3 million in 2000, . $12.2 million in 1999, and . $10.5 million in 1998. At December 31, 2000, we owed future minimum payments for long-term, noncancelable, operating leases as follows: Year - ---------------------------------------------------------- (In millions) 2001 $ 7.8 2002 6.4 2003 5.0 2004 3.5 2005 2.9 Thereafter 8.1 - ---------------------------------------------------------- Total future minimum lease payments $33.7 ========================================================== 10 COMMITMENTS, GUARANTEES, AND CONTINGENCIES Commitments - ----------- We have made substantial commitments in connection with our domestic merchant energy business construction program for future years. In addition, we have two long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2001 and 2013. We made payments under these contracts of: . $77.3 million in 2000, . $67.8 million in 1999, and . $70.7 million in 1998. At December 31, 2000, we estimate our future payments for capacity and energy that we are obligated to buy under these contracts to be: Year - -------------------------------------------------------------- (In millions) 2001 $ 40.2 2002 16.4 2003 16.0 2004 15.5 2005 15.1 Thereafter 113.6 - -------------------------------------------------------------- Total estimated future payments for capacity and energy under long-term contracts $216.8 ============================================================== Portions of these contracts became uneconomic upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts as discussed in Note 4. At December 31, 2000, the accrued portion of these contracts was $21.2 million. Our domestic merchant energy business has committed to contribute additional capital and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest. At December 31, 2000, the total amount of investment requirements committed to by our domestic merchant energy business was $181.0 million. BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $40 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against BGE and has no recourse against BGE Home Products & Services. BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 2000, BGE had sold $23.9 million and BGE Home Products & Services had sold $42.5 million of receivables under these agreements. Planned Acquisition - ------------------- On December 12, 2000, we announced that a subsidiary of Constellation Nuclear will purchase 1,550 megawatts of the 1,757 megawatts total generating capacity of the Nine Mile Point nuclear power plant, located in Scriba, New York. The subsidiary of Constellation Nuclear will buy 100 percent of Unit 1 and 82 percent of Unit 2 for $815 million, including $78 million for fuel. The sale is expected to close in mid-2001 after receipt of all necessary regulatory approvals. Key regulatory approvals are required from the NRC, Federal Energy Regulatory Commission (FERC), and the New York State Public Service Commission. 74 One-half of the purchase price, or $407.5 million, is due at the closing of the transaction. The sellers will finance the remaining half of the purchase price at an 11.0% fixed rate for a period of five years with equal annual principal repayments. Nine Mile Point includes two boiling-water reactors. Unit 1 is a 609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148- megawatt reactor that began operation in 1988. Niagara Mohawk Power Corporation is the sole owner of Nine Mile Point Unit 1. The co-owners of Nine Mile Point Unit 2 that are selling their interests include Niagara Mohawk (41 percent), New York State Electric and Gas (18 percent), Rochester Gas & Electric Corporation (14 percent), and Central Hudson Gas & Electric Corporation (9 percent). The Long Island Power Authority, which owns 18 percent of Nine Mile Point Unit 2, has chosen not to sell its portion at this time. The terms of the transaction include power purchase agreements whereby we have agreed to sell 90 percent of our share of the Nine Mile Point plant's output back to the sellers for approximately 10 years at an average price of nearly $35 per megawatt-hour over the term of the power purchase agreements. The contracts for the output of both plants are based on operation of the individual units. The sellers will transfer approximately $450 million in decommissioning funds at the time of closing. We believe this transfer is sufficient to meet the decommissioning requirements for our share of the Nine Mile Point site. Separation Initiatives - ---------------------- On October 23, 2000, we announced three initiatives to advance our growth strategies. The first initiative is that we entered into an agreement (the "Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a 17.5% equity interest in our domestic merchant energy business, which will be consolidated under a single holding company ("Holdco"). Goldman Sachs will also acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to certain adjustments). The warrant is exercisable six months after Holdco's common stock becomes publicly available. The amount of common stock which Goldman Sachs may receive upon exercise will be equal to the excess of the market price of Holdco's common stock at the time of exercise over the exercise price of $60 per share for all the stock subject to the warrant, divided by the market price. Holdco may at its option pay Goldman Sachs such excess in cash. Goldman Sachs is acquiring its interest and the warrant in exchange for $250 million in cash (subject to adjustment in certain instances) and certain assets related to our power marketing operation. At closing, Goldman Sachs' existing services agreement with our power marketing operation will terminate. The second initiative is a plan to separate our domestic merchant energy business from our remaining businesses. The separation will create two stand- alone, publicly traded energy companies. One will be a merchant energy business engaged in wholesale power marketing and generation under the name "Constellation Energy Group" after the separation. The other will be a regional retail energy delivery and energy services company, BGE Corp., which will include BGE, our other nonregulated businesses, and our investment in Orion Power Holdings, Inc. ("Orion"). As a result of the separation, shareholders will continue to own all of Constellation Energy's current businesses through their ownership of the new Constellation Energy Group and BGE Corp. The third initiative is a change in our common stock dividend policy effective April 2001. In a move closely aligned with our separation plan, effective April 2001, our annual dividend is expected to be set at $.48 per share. After the business separation, BGE Corp. expects to pay initial annual dividends of $.48 per share. Constellation Energy Group, as a growing merchant energy company, initially expects to reinvest its earnings in order to fund its growth plans and not to pay a dividend. The closing of the transaction with Goldman Sachs and the separation are subject to customary closing conditions and contingent upon obtaining regulatory approvals and a Private Letter Ruling from the Internal Revenue Service regarding certain tax matters. The transaction and separation are expected to be completed by mid to late 2001. Guarantees - ---------- At December 31, 2000, Constellation Energy issued guarantees in an amount up to $825.8 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries. The actual subsidiary liabilities related to these guarantees totaled $586.6 million at December 31, 2000. At December 31, 2000, our nonregulated businesses had guaranteed outstanding loans and letters of credit of certain power projects and real estate projects totaling $50.1 million. Our nonregulated businesses also guarantee certain other borrowings of various power projects and real estate projects. BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation. The maximum amount of our guarantee is $23 million. At December 31, 2000, Safe Harbor Water Power Corporation had outstanding debt of $20.0 million, of which $13.3 million is guaranteed by BGE. We assess the risk of loss from these guarantees to be minimal. Environmental Matters - --------------------- We are subject to regulation by various federal, state and local authorities with regard to: . air quality, . water quality, . chemical and waste management and disposal, and . other environmental matters. We discuss the significant matters below. Clean Air - --------- The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations--Title IV and Title I. Title IV addresses emissions of sulfur dioxide. For our older plants, we meet the requirements through a combination of switching fuels and allowance trading. For newer plants, we meet the requirements primarily through facility design, and operational and pollution controls. 75 Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued regulations, effective October 18, 1999, which required up to 65% NOx emissions reductions by May 1, 2000. We entered into a settlement agreement with the MDE since we could not meet this deadline. Under the terms of the settlement agreement, we will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that required up to 85% NOx emissions reduction by 22 states including Maryland and Pennsylvania. Maryland and Pennsylvania expect to meet the requirements of the rule by 2003. The emissions reduction equipment installations discussed above will allow us to meet these requirements in Maryland. The generating plants in Pennsylvania also will install emissions reduction equipment by 2003 to meet the 85% reduction requirement. We currently estimate that the controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately $150 million. Through December 31, 2000, we have spent approximately $115 million to meet the 65% reduction requirements. We estimate the additional cost for the EPA's 85% reduction requirements to be approximately $90 million by the end of 2003. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. While these standards may require increased controls at our fossil generating plants in the future, implementation, if required, would 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. In December 2000, the EPA issued a determination that coal-fired power plant mercury emissions will be controlled. Final regulations are expected to be issued in 2004 with controls required by 2007. The costs of these controls cannot be estimated at this time since the level of control or system to implement them have not yet been established. We received letters from the EPA requesting us to provide certain information under Section 114 of the federal Clean Air Act regarding some of our electric generating plants. 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. We have provided the EPA the requested information. We believe our generating plants have been operated in accordance with the Clean Air Act and the rules implementing the Clean Air Act. However, we cannot estimate the impact of this inquiry on our generating plants, and our financial results, at this time. Waste Disposal - -------------- The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA. Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the MDE that required us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million. We discuss this further in Note 5. Through December 31, 2000, we have spent approximately $35 million for remediation at this site. We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results. Litigation - ---------- In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below. Employment Discrimination - ------------------------- Miller 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. 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. 76 Moore v. Constellation Energy Group--This action was filed on October 23, 2000 in the U.S. District Court for the District of Maryland by an employee alleging employment discrimination. Besides Constellation Energy, BGE and Constellation Holdings, Inc. are also named defendants. The Equal Employment Opportunity Commission has previously concluded that it was unable to establish a violation of law. The plaintiff seeks, among other things, unspecific monetary damages and back pay. We believe this case is without merit. Asbestos - -------- Since 1993, we have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that we 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. We described these claims in a Report on Form 8-K filed August 20, 1993. We are involved in these claims with approximately 70 other defendants. Approximately 530 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: . the identity of our facilities at which the plaintiffs allegedly worked as contractors, . the names of the plaintiff's employers, and . the date on which the exposure allegedly occurred. To date, 29 of these cases were settled for amounts that were not significant. The second type is claims by one manufacturer--Pittsburgh Corning Corp. (PCC)--against us and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute this claim. 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 350 cases have been resolved, all without any payment by BGE. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: . the identity of our facilities containing asbestos manufactured by the manufacturer, . the relationship (if any) of each of the individual plaintiffs to us, . the settlement amounts for any individual plaintiffs who are shown to have had a relationship to us, and . the dates on which/places at which the exposure allegedly occurred. Until the relevant facts for both types of claims are determined, we are unable to estimate what our 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, our potential liability could be material. Restructuring Order - ------------------- In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA), Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to delay implementation of the Restructuring Order, pending a decision on the merits of the appeals by the court. On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of standing (the right of a party to bring a lawsuit to court) and denied its motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals. MAPSA subsequently filed several appeals with the Maryland Court of Special Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court. The effect of the appeals was to delay the implementation of customer choice in BGE's service territory. However, on August 4, 2000, the delay was rescinded and BGE retroactively adjusted its rates as if customer choice had been implemented July 1, 2000. On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. We believe that this appeal is without merit. However, we cannot predict the timing or outcome of this case, which, if adverse, could have a material effect on our, and BGE's, financial results. Asset Transfer Order - -------------------- On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's generation assets issued on June 19, 2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing on the petition on August 23, 2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. We also believe that this appeal is without merit. However, we cannot predict the timing or outcome of this case, which, if adverse, could have a material effect on our, and BGE's, financial results. Calvert Cliffs' License Renewal - ------------------------------- On April 11, 2000 the United States Court of Appeals for the District of Columbia Circuit, in National Whistleblowers Center v. Nuclear Regulatory Commission and Baltimore Gas and Electric Company, upheld the NRC's denial of the Center's motion to intervene in BGE's license renewal proceeding. The NRC had denied the Center's motion to intervene for failing to file timely contentions. The Center filed a petition for certiorari, a request to hear an appeal, with the U.S. Supreme Court, which was denied. 77 Nuclear Insurance - ----------------- If there were an accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse financial effect on us. The primary contingencies that would result from an incident at Calvert Cliffs could include: . physical damage to the plant, . recoverability of replacement power costs, and . our liability to third parties for property damage and bodily injury. We have insurance policies that cover these contingencies, but the policies have certain industry standard exclusions. Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits. Insurance for Calvert Cliffs and Third Party Claims - --------------------------------------------------- For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 12 weeks, we have insurance coverage for replacement power costs up to $490.0 million per unit, provided by an industry mutual insurance company. This amount can be reduced by up to $98.0 million per unit if an outage at both units of the plant is caused by a single insured physical damage loss. 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 $15.4 million. In addition we, as well as others, could be charged for a portion of any third party claims associated with a nuclear incident at any commercial nuclear power plant in the country. At December 31, 2000, the limit for third party claims from a nuclear incident is $9.54 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident. That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims - ------------------------------------- As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers. On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below. 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. All nuclear worker claims reported prior to January 1, 1998 are still covered by the old insurance policies. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies for the next seven years. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be assessed, with our share being up to $6.3 million. If claims under these polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed in this section) would apply. California Power Purchase Agreements - ------------------------------------ Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $297.9 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Under these agreements, the projects supply electricity to utility companies at: . a fixed rate for capacity and energy for the first 10 years of the agreements, and . a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements. Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next- available source of generation to service the demands on its system. We use the term "transitioned" to describe when the 10-year periods for fixed energy rates have expired for these power generation projects and they began supplying electricity at variable rates. In 2000, the last four projects transitioned to variable rates. Prior to 2000, the projects that have transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. In 2000, the prices received under these agreements were higher due to the increases in the variable-rate pricing terms. 78 11 FAIR VALUE OF ASSETS AND LIABILITIES FROM ENERGY TRADING ACTIVITIES AND FINANCIAL INSTRUMENTS Assets and Liabilities from Energy Trading Activities - ----------------------------------------------------- As described in Note 1, we report assets and liabilities from energy trading activities at fair value. At December 31, 2000, the notional amounts and terms of trading instruments at Constellation Power Source were as follows:
Maximum Terms in Purchased Sold Years - ---------------------------------------------------------------- (Notional amounts in millions) Electric energy (megawatt-hours) 391.3 144.2 21 Electric capacity (megawatt-hours) 66.8 84.9 21 Oil (barrels) 8.5 11.9 5 Natural gas (millions of British thermal units) 373.5 316.3 9
Notional amounts express the contractual volume of transactions but do not necessarily represent the amounts to be exchanged by the parties to the instruments. Accordingly, notional amounts do not accurately measure our exposure to market or credit risk. Financial Instruments - --------------------- The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We used the following methods and assumptions in estimating fair value disclosures for financial instruments. . Cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portion of long- term debt, and certain deferred credits and other liabilities: The amounts reported in the Consolidated Balance Sheets approximate fair value. . Investments and other assets where it was practicable to estimate fair value: The fair value is based on quoted market prices where available. . Long-term debt: The fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates. We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately later in this section.
At December 31, 2000 1999 - ---------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value - ---------------------------------------------------------------------- (In millions) Investments and other assets for which it is: Practicable to estimate fair value $349.8 $ 349.8 $ 313.3 $ 313.3 Not practicable to estimate fair value 43.5 N/A 46.7 N/A Fixed-rate long-term debt 2,734.1 2,819.9 2,728.9 2,637.3 Variable-rate long- term debt 1,331.8 1,243.3 654.8 654.8
It was not practicable to estimate the fair value of investments held by our nonregulated businesses in: . several financial partnerships that invest in nonpublic debt and equity securities, and . several partnerships that own solar powered energy production facilities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets. The investments in financial partnerships totaled $32.7 million at December 31, 2000 and $35.8 million at December 31, 1999, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $6.1 billion at December 31, 1999 (which is the latest information available). The investments in solar powered energy production facility partnerships totaled $10.8 million at December 31, 2000 and $10.9 million at December 31, 1999, representing ownership interests up to 13%. The total assets of all of these partnerships totaled $26.7 million at December 31, 1999 (which is the latest information available). Guarantees - ---------- It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries. Constellation Energy guaranteed outstanding debt of $341.0 million at December 31, 2000 and $16.5 million at December 31, 1999. Our nonregulated businesses guaranteed outstanding debt totaling $50.1 million at December 31, 2000 and $48.8 million at December 31, 1999. BGE guaranteed outstanding debt of $13.3 million at December 31, 2000 and $13.6 million at December 31, 1999. We do not anticipate that we will need to fund these guarantees. 79 12 STOCK-BASED COMPENSATION As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under our existing long-term incentive plans, we can issue awards that include stock options and performance-based restricted stock to officers and key employees. Under the plans, we can issue up to a total of 6,000,000 shares for these awards. Stock Options - ------------- In May 2000, our Board of Directors approved the issuance of non-qualified stock options. The options were granted at prices not less than the market value of the stock at the date of grant, generally become exercisable ratably over a three-year period beginning one-year from the date of grant, and expire ten years from the date of grant. The grants provide for the exercise of the options on a pro-rata basis for service to date upon the separation of our businesses. The tables below do not reflect the impact of the business separation. In accordance with APB No. 25, no compensation expense is recognized for the stock option awards. Summarized information for our stock option awards is as follows:
Weighted- Average Shares Exercise Price - ---------------------------------------------------------------------- (In thousands, except per share amounts) Outstanding at January 1, 2000 -- $ -- Granted 2,462 34.64 Exercised -- -- Cancelled/Expired (42) (34.25) - ---------------------------------------------------------------------- Outstanding at December 31, 2000 2,420 $ 34.65 ====================================================================== Exercisable at December 31, 2000 -- -- ====================================================================== Weighted-average fair value per share of options granted during year $ 5.60 ======================================================================
A summary of the weighted-average remaining contractual life and the weighted- average exercise price of options outstanding as of December 31, 2000 is presented below:
Weighted- Options Average Range of Outstanding at Weighted- Remaining Exercise December 31, 2000 Average Contractual Prices (In thousands) Exercise Price Life (In years) - ------------------------------------------------------------------------------ $34.25-$40.72 2,420 $34.65 9.4
Performance-Based Restricted Stock Awards - ----------------------------------------- In addition, we issue common stock based on meeting certain performance and service goals that vests to participants at various times ranging from three to five years. In accordance with APB No. 25, we recognize compensation expense for our restricted stock awards. Compensation expense recorded was $16.3 million for 2000 and $10.5 million for 1999. Prior to 1999, compensation expense was not material. Summarized share information for our restricted stock awards is as follows:
2000 1999 - --------------------------------------------------------------- (In thousands, except per share amounts) Outstanding, beginning of year 323 350 Granted 353 358 Released to participants (277) (362) Cancelled (22) (23) - --------------------------------------------------------------- Outstanding, end of year 377 323 =============================================================== Weighted-average fair value per share of restricted stock granted during the year $32.89 $28.61 ===============================================================
Pro-forma Information - --------------------- Disclosure of pro-forma information regarding net income and earnings per share is required under SFAS No. 123, which uses the fair value method. The fair values of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions: 2000 - --------------------------------------------------------- Risk-free interest rate 6.37% Expected life (in years) 10.0 Expected market price volatility factors 21.0% Expected dividend yields 5.7% The effect of applying SFAS No. 123 to our stock-based awards results in net income and earnings per share that are not materially different from amounts reported. 80 13 QUARTERLY FINANCIAL DATA (UNAUDITED) Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. 2000 Quarterly Data--Constellation Energy - -----------------------------------------
Earnings Earnings Income Applicable Per Share from to Common of Common Revenue Operations Stock Stock - -------------------------------------------------------------------------------------- (In millions, except per-share amounts) Quarter Ended March 31 $ 992.2 $182.8 $ 72.1 $0.48 June 30 868.4 133.9 39.6 0.26 September 30 981.6 315.4 147.5 0.98 December 31 1,036.3 208.1 86.1 0.57 - -------------------------------------------------------------------------------------- Year Ended December 31 $3,878.5 $840.2 $345.3 $2.30 ======================================================================================
2000 Quarterly Data--BGE - ------------------------
Earnings Income Applicable from to Common Revenue Operations Stock - ----------------------------------------------------------------------- (In millions, except per-share amounts) Quarter Ended March 31 $ 720.7 $133.9 $ 50.9 June 30 659.4 126.7 49.1 September 30 690.0 65.0 10.0 December 31 676.7 84.5 20.3 - ----------------------------------------------------------------------- Year Ended December 31 $2,746.8 $410.1 $130.3 =======================================================================
First quarter results include: - ----------------------------- Constellation Energy and BGE - ---------------------------- . a $2.5 million after-tax expense for BGE Employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP)(see Note 2), . $37.5 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order (see the "Electric Depreciation and Amortization Expense" section of Management's Discussion and Analysis), Second quarter results include: - ------------------------------ Constellation Energy and BGE - ---------------------------- . a $1.7 million after-tax expense for the TVSERP (see Note 2), . $37.5 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order, and Constellation Energy - -------------------- . a $15.0 million after-tax deregulation transition cost to a third party incurred by our power marketing operation to provide BGE's standard offer service requirements (see Note 2). 1999 Quarterly Data--Constellation Energy - -----------------------------------------
Earnings Earnings Income Applicable Per Share from to Common of Common Revenue Operations Stock Stock - -------------------------------------------------------------------------------------- (In millions, except per-share amounts) Quarter Ended March 31 $ 983.4 $198.1 $ 82.8 $ 0.55 June 30 858.5 163.9 68.0 0.45 September 30 1,010.2 277.7 136.1 0.91 December 31 934.1 120.2 (26.8) (0.18) - -------------------------------------------------------------------------------------- Year Ended December 31 $3,786.2 $759.9 $260.1 $1.74 ======================================================================================
1999 Quarterly Data--BGE - ------------------------
Earnings Income Applicable from to Common Revenue Operations Stock - ----------------------------------------------------------------------- (In millions, except per-share amounts) Quarter Ended March 31 $ 983.4 $198.1 $ 82.8 June 30 682.0 140.9 57.8 September 30 756.0 283.3 151.5 December 31 670.8 82.0 (43.5) - ----------------------------------------------------------------------- Year Ended December 31 $3,092.2 $704.3 $248.6 =======================================================================
Constellation Energy's second quarter results include a $3.6 million after-tax write-down of a financial investment (see Note 3). Third quarter results include: - ----------------------------- Constellation Energy and BGE - ---------------------------- . $7.5 million associated with Hurricane Floyd (see the "Electric Operations and Maintenance Expenses" section of Management's Discussion and Analysis), . a $37.5 million deferral of revenues collected associated with the deregulation of our electric generation business (see Note 5), Constellation Energy - -------------------- . a $17.3 million after-tax write-down of a financial investment (see Note 3), . a $6.7 million after-tax write-off of a power project (see Note 3), and . a $3.4 million after-tax write-down of certain senior-living facilities (see Note 2). Fourth quarter results include: - ------------------------------ Constellation Energy and BGE - ---------------------------- . a $66.3 million extraordinary charge associated with the Restructuring Order (see Note 4), . the recognition of the $37.5 million of revenues that were deferred in the third quarter (see above), . $75 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order, Constellation Energy - -------------------- . a $4.9 million after-tax gain on a financial investment (see Note 3), . $12.0 million after-tax write-downs of certain power projects (see Note 3), and . a $2.4 million after-tax write-down of certain senior-living facilities (see Note 2). The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding. 81 14 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, 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 the energy and capacity required to meet its standard offer service obligations for the first three years 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 $581.0 million for the year ended December 31, 2000. In addition, BGE receives charges from Constellation Energy for certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $21.6 million for the year ended December 31, 2000. These costs were not material in 1999 due to the creation of Constellation Energy effective April 30, 1999 and the subsequent transfer of certain BGE employees to the holding company later that year. Balance Sheet - ------------- As a result of the deregulation of electric generation, BGE transferred its generation assets to nonregulated affiliates of Constellation Energy effective July 1, 2000. In conjunction with this transfer, Constellation Power Source Generation, Inc. issued approximately $366 million in unsecured promissory notes to BGE. Repayments of the notes by Constellation Power Source Generation, Inc. will be used exclusively to service current maturities of certain BGE long-term debt. As of December 31, 2000, $87 million of these notes are still outstanding and will mature on March 14, 2001. 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. Management believes its allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities. 82 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. - -------------------------------------------------------------------------------- PART III BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section related to BGE are not presented. Item 10. Directors and Executive Officers of the Registrant The information required by this item with respect to directors is set forth on pages 4 through 6 under Election of Constellation Energy Directors in the Proxy Statement and is incorporated herein by reference. The information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth in Item 4 of Part I of this Form 10-K under Executive Officers of the Registrant. Item 11. Executive Compensation The information required by this item is set forth on pages 7 and 8 under Directors' Compensation, on page 8 under Compensation Committee Interlocks and Insider Participation, on pages 11 through 14 under Executive Compensation, on page 15 under Common Stock Performance Graph and on pages 15 through 18 under Report of Committee on Management on Executive Compensation in the Proxy Statement and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required by this item regarding security ownership of certain beneficial owners and management is set forth on pages 9 and 10 under Security Ownership in the Proxy Statement and is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions The information required by this item is set forth on page 8 under Certain Relationships and Transactions and Compensation Committee Interlocks and Insider Participation in the Proxy Statement and is incorporated herein by reference. 83 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) The following documents are filed as a part of this Report: 1. Financial Statements: Report of Independent Accountants dated January 17, 2001 of PricewaterhouseCoopers LLP Consolidated Statements of Income--Constellation Energy Group for three years ended December 31, 2000 Consolidated Statements of Comprehensive Income--Constellation Energy Group for three years ended December 31, 2000 Consolidated Balance Sheets--Constellation Energy Group at December 31, 2000 and December 31, 1999 Consolidated Statements of Cash Flows--Constellation Energy Group for three years ended December 31, 2000 Consolidated Statements of Common Shareholders' Equity--Constellation Energy Group for three years ended December 31, 2000 Consolidated Statements of Capitalization--Constellation Energy Group at December 31, 2000 and December 31, 1999 Consolidated Statements of Income Taxes--Constellation Energy Group for three years ended December 31, 2000 Consolidated Statements of Income--Baltimore Gas and Electric Company for three years ended December 31, 2000 Consolidated Statements of Comprehensive Income--Baltimore Gas and Electric Company for three years ended December 31, 2000 Consolidated Balance Sheets--Baltimore Gas and Electric Company at December 31, 2000 and December 31, 1999 Consolidated Statements of Cash Flows--Baltimore Gas and Electric Company for three years ended December 31, 2000 Notes to Consolidated Financial Statements 2. Financial Statement Schedules: Schedule II--Valuation and Qualifying Accounts Schedules other than Schedule II are omitted as not applicable or not required. 3. Exhibits Required by Item 601 of Regulation S-K.
Exhibit Number ------- *2 -- Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.) *2(a) -- Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) *2(b) -- Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) *3(a) -- Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1- 1910.) *3(b) -- Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.) *3(c) -- Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) *3(d) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1- 1910.) *3(e) -- Bylaws of Constellation Energy Group, Inc., as amended to February 16, 2001. (Designated as Exhibit No. 3(d) in Form S-3 dated March 5, 2001, File No. 333-56572.)
84 *3(f) -- Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.) *4(a) -- Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.) *4(b) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
Designated In ------------------------------------------------------- Exhibit Dated File No. Number ----- -------- ------- *July 15, 1977 2-59772 2-3 (3 Indentures) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(c) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).) *4(d) -- Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(e) -- Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(f) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(g) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(h) -- Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(i) -- Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8- K dated December 20, 2000, File No. 1-1910.) *10(a) -- Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-19101.) 10(b) -- Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. *10(c) -- Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(b) in Form 10-Q dated November 12, 1999, File Nos. 1-12869 and 1-19101.)
85 *10(d) -- Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10(a) in Form 10- Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(e) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(f) -- Summary of severance arrangement for a named executive officer. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) 10(g) -- Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. *10(h) -- Form of Severance Agreements between Baltimore Gas and Electric Company and seven key employees. (Designated as Exhibit No. 10(j) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(i) -- Summary of enhanced retirement benefits for a named executive officer. (Designated as Exhibit No. 10(l) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(j) -- Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(k) -- Constellation Energy Group, Inc. Long-Term Incentive Plan. (Designated as Exhibit No. 10(b) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(l) -- Full Requirements Service Agreement Between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1- 12869 and 1-1910.) *10(m) -- Constellation Energy Group, Inc. Benefits Restoration Plan. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) 10(n) -- Constellation Energy Group, Inc. Supplemental Pension Plan. 10(o) -- Constellation Energy Group, Inc. Senior Executive Supplemental Plan. *10(p) -- Constellation Energy Group, Inc. Supplemental Benefits Plan. (Designated as Exhibit No. 10(e) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) 12(a) -- Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges. 12(b) -- Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 -- Subsidiaries of the Registrant. 23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
* Incorporated by Reference. (b) Reports on Form 8-K:
Date Filed Item Reported ---------- ------------- Constellation Energy and BGE October 23, 2000 Item 5. Other Events Item 7. Financial Statements and Exhibits December 12, 2000 Item 5. Other Events Item 7. Financial Statements and Exhibits BGE December 20, 2000 Item 5. Other Events
86 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E -------- --------- ------------------- -------------- --------- Additions ------------------- Balance Charged Charged at to costs to other Balance beginning and accounts-- (Deductions)-- at end of Description of period expenses describe describe period - ----------- --------- -------- ---------- -------------- --------- (in millions) Reserves deducted in the Balance Sheet from the assets to which they apply: Constellation Energy Accumulated Provision for Uncollectibles 2000.................. $ 34.8 $21.1 $ -- $(34.6)(A) $ 21.3 1999.................. 35.4 21.5 -- (22.1)(A) 34.8 1998.................. 24.1 28.0 -- (16.7)(A) 35.4 Valuation Allowance -- Net unrealized (gain) loss on available for sale securities 2000.................. 0.2 -- (33.9)(B) -- (33.7) 1999.................. (9.4) -- 9.6 (B) -- 0.2 1998.................. (7.6) -- (1.8)(B) -- (9.4) Net unrealized (gain) loss on nuclear decommissioning trust fund 2000.................. (40.5) -- 5.8 (C) -- (34.7) 1999.................. (23.9) -- (16.6)(C) -- (40.5) 1998.................. (10.0) -- (13.9)(C) -- (23.9) Assets from trading activities reserves 2000.................. (27.5) -- (26.9)(D) -- (54.4) 1999.................. (0.6) -- (26.9)(D) -- (27.5) 1998.................. -- -- (0.6)(D) -- (0.6) BGE Accumulated Provision for Uncollectibles 2000.................. 13.0 16.4 -- (16.0)(A) 13.4 1999.................. 35.4 17.6 -- (40.0)(E) 13.0 1998.................. 24.1 28.0 -- (16.7)(A) 35.4 Valuation Allowance -- Net unrealized (gain) loss on available for sale securities 2000.................. -- -- -- -- -- 1999.................. (9.4) -- (5.3)(B) 14.7 (F) -- 1998.................. (7.6) -- (1.8)(B) -- (9.4) Net unrealized (gain) loss on nuclear decommissioning trust fund 2000.................. (40.5) -- (1.8)(C) 42.3 (G) -- 1999.................. (23.9) -- (16.6)(C) -- (40.5) 1998.................. (10.0) -- (13.9)(C) -- (23.9)
(A) Represents principally net amounts charged off as uncollectible. (B) Represents net unrealized (gains)/losses (credited)/charged to accumulated other comprehensive income. (C) Represents net unrealized (gains)/losses (credited)/charged to accumulated depreciation. (D) Represents a reserve from assets for energy trading activities charged to revenues. (E) Represents approximately $17 million charged off as uncollectible and approximately $23 million transferred from BGE to Constellation Energy as a result of the formation of the holding company. (F) Represents amount transferred from BGE to Constellation Energy as a result of the formation of the holding company. (G) Represents balance transferred to a subsidiary of Constellation Nuclear, LLC on July 1, 2000. 87 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. CONSTELLATION ENERGY GROUP, INC. (Registrant) Date: March 30, 2001 By /s/ C. H. Poindexter _____________________________ C. H. Poindexter Chairman of the Board, President, and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- Principal executive officer and director: By /s/ C. H. Poindexter Chairman of the Board, March 30, 2001 _____________________ President, Chief C. H. Poindexter Executive Officer, and Director Principal financial and accounting officer: By /s/ D. A. Brune Vice President, Chief March 30, 2001 _______________________ Financial Officer and D. A. Brune Secretary Directors: /s/ H. F. Baldwin Director March 30, 2001 _______________________ H. F. Baldwin /s/ D. L. Becker Director March 30, 2001 _______________________ D. L. Becker /s/ J. T. Brady Director March 30, 2001 _______________________ J. T. Brady /s/ B. B. Byron Director March 30, 2001 _______________________ B. B. Byron /s/ J. O. Cole Director March 30, 2001 _______________________ J. O. Cole /s/ D. A. Colussy _______________________ Director March 30, 2001 D. A. Colussy /s/ E. A. Crooke Director March 30, 2001 _______________________ E. A. Crooke /s/ J. R. Curtis Director March 30, 2001 _______________________ J. R. Curtiss /s/ R. W. Gale Director March 30, 2001 _______________________ R. W. Gale /s/ J. W. Geckle Director March 30, 2001 _______________________ J. W. Geckle
88
Signature Title Date --------- ----- ---- /s/ F. A. Hrabowski III Director March 30, 2001 __________________________ F. A. Hrabowski III /s/ R. J. Hurst Director March 30, 2001 __________________________ R. J. Hurst /s/ N. Lampton Director March 30, 2001 __________________________ N. Lampton /s/ C. R. Larson Director March 30, 2001 __________________________ C. R. Larson /s/ G. L. Russell, Jr. Director March 30, 2001 __________________________ G. L. Russell, Jr. /s/ M. A. Shattuck, III Director March 30, 2001 __________________________ M. A. Shattuck, III /s/ M. D. Sullivan Director March 30, 2001 __________________________ M. D. Sullivan
89 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. BALTIMORE GAS AND ELECTRIC COMPANY (Registrant) Date: March 30, 2001 By /s/ F. O. Heintz __________________________________ F. O. Heintz President, and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- Principal executive officer and director: By /s/ F. O. Heintz President Chief Executive March 30, 2001 _________________________ Officer, and Director F. O. Heintz Principal financial and accounting officer and director: By /s/ D. A. Brune _______________________ Vice President, Chief March 30, 2001 D. A. Brune Financial Officer, Secretary, and Director Directors: /s/ C. H. Poindexter Director March 30, 2001 _______________________ C. H. Poindexter /s/ R. E. Denton Director March 30, 2001 _______________________ R. E. Denton /s/ T. F. Brady Director March 30, 2001 _______________________ T. F. Brady /s/ E. A. Crooke Director March 30, 2001 _______________________ E. A. Crooke
90 EXHIBIT INDEX
Exhibit Number ------- *2 -- Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.) *2(a) -- Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) *2(b) -- Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) *3(a) -- Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1- 1910.) *3(b) -- Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.) *3(c) -- Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) *3(d) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1- 1910.) *3(e) -- Bylaws of Constellation Energy Group, Inc., as amended to February 16, 2001. (Designated as Exhibit No. 3(d) in Form S-3 dated March 5, 2001, File No. 333-56572.) *3(f) -- Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1- 1910.) *4(a) -- Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.) *4(b) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
Designated In ------------------------------------------------------- Exhibit Dated File No. Number ----- -------- ------- *July 15, 1977 2-59772 2-3 (3 Indentures) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(c) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8- K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
91 *4(d) -- Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(e) -- Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(f) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(g) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(h) -- Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(i) -- Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8- K dated December 20, 2000, File No. 1-1910.) *10(a) -- Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-19101.) 10(b) -- Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. *10(c) -- Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(b) in Form 10-Q dated November 12, 1999, File Nos. 1-12869 and 1-19101.) *10(d) -- Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10(a) in Form 10- Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(e) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(f) -- Summary of severance arrangement for a named executive officer. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) 10(g) -- Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. *10(h) -- Form of Severance Agreements between Baltimore Gas and Electric Company and seven key employees. (Designated as Exhibit No. 10(j) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(i) -- Summary of enhanced retirement benefits for a named executive officer. (Designated as Exhibit No. 10(l) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(j) -- Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(k) -- Constellation Energy Group, Inc. Long-Term Incentive Plan. (Designated as Exhibit No. 10(b) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-19101.) *10(l) -- Full Requirements Service Agreement Between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1- 12869 and 1-1910.) *10(m) -- Constellation Energy Group, Inc. Benefits Restoration Plan. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) 10(n) -- Constellation Energy Group, Inc. Supplemental Pension Plan. 10(o) -- Constellation Energy Group, Inc. Senior Executive Supplemental Plan.
92 *10(p) -- Constellation Energy Group, Inc. Supplemental Benefits Plan. (Designated as Exhibit No. 10(e) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) 12(a) -- Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges. 12(b) -- Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 -- Subsidiaries of the Registrant. 23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
* Incorporated by Reference. 93 EX-10.B 2 0002.txt LONG-TERM INCENTIVE PLAN Exhibit 10(b) Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan (Plan) 1. Objective. The objective of this Plan is to increase shareholder value by --------- providing a long-term incentive to reward officers and key employees of CEG and its Subsidiaries, who are mainly responsible for the continued growth, development, and financial success of CEG and its Subsidiaries, for the continued profitable performance of CEG and its subsidiaries. The Plan is also designed to permit CEG and its Subsidiaries to retain talented and motivated officers and key employees and to increase their ownership of CEG common stock. 2. Definitions. All singular terms defined in this Plan will include the ----------- plural and vice versa. As used herein, the following terms will have the meaning specified below: "Award" means individually or collectively, Restricted Stock, Options, Performance Units, Stock Appreciation Rights, or Dividend Equivalents granted under this Plan. "Board" means the Board of Directors of CEG. "Book Value" means the book value of a share of Stock determined in accordance with CEG's regular accounting practices as of the last business day of the month immediately preceding the month in which a Stock Appreciation Right is exercised as provided in Section 10. "CEG" means Constellation Energy Group, Inc., a Maryland corporation, or its successor, including any "New Company" as provided in Section 14I. "Code" means the Internal Revenue Code of 1986, as amended. Reference in the Plan to any section of the Code will be deemed to include any amendments or successor provisions to such section and any regulations promulgated thereunder. "Committee" means the Committee on Management of the Board, provided, however, that if such Committee fails to satisfy the disinterested administration provisions of Section 16b-3 of the 1934 Act, "Committee" shall mean a committee of directors of CEG who satisfy the disinterested person requirements of such Section. "Date of Grant" means the date on which the granting of an Award is authorized by the Committee or such later date as may be specified by the Committee in such authorization. "Date of Retirement" means the date of Retirement or Early Retirement. "Disability" means the determination that a Participant is "disabled" under the CEG disability plan in effect at that time. "Dividend Equivalent" means an award granted under Section 11. "Early Retirement" means retirement prior to the Normal Retirement Date. "Earned Performance Award" means an actual award of a specified number of Performance Units (or shares of Restricted Stock, as the context requires) which the Committee has determined have been earned and are payable (or, in the case of Restricted Stock, earned and with respect to which restrictions will lapse) for a particular Performance Period. "Eligible Employee" means any person employed by CEG or a Subsidiary on a regularly scheduled basis who satisfies all of the requirements of Section 5. "Exercise Period" means the period or periods during which a Stock Appreciation Right is exercisable as described in Section 10. "Fair Market Value" means the average of the highest and lowest price at which the Stock was sold regular way on the New York Stock Exchange- Composite Transactions on a specified date. "Incentive Stock Option" means an incentive stock option within the meaning of Section 422 of the Code. "1934 Act" means the Securities Exchange Act of 1934, as amended. "Normal Retirement Date" is the retirement date as described in the Pension Plan or a Subsidiary's retirement or pension plan. "Option" or "Stock Option" means either a nonqualified stock option or an incentive stock option granted under Section 8. "Option Period" or "Option Periods" means the period or periods during which an Option is exercisable as described in Section 8. "Participant" means an employee of CEG or a Subsidiary who has been granted an Award under this Plan. "Pension Plan" means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time. "Performance-Based" means that in determining the amount of a Restricted Stock Award payout, the Committee will take into account the performance of the Participant, CEG, one or more Subsidiaries, or any combination thereof. "Performance Period" means a period of time, established by the Committee at the time an Award is granted, during which corporate and/or individual performance is measured. 2 "Performance Unit" means a unit of measurement equivalent to such amount or measure as defined by the Committee which may include, but is not limited to, dollars, market value shares, or book value shares. "Plan Administrator" means, as set forth in Section 4, the Committee. "Restricted Stock" means an Award granted under Section 7. "Retirement" means retirement on or after the "Normal Retirement Date" (as such term is defined in the Pension Plan or a Subsidiary's retirement or pension plan). "Service-Based" means that in determining the amount of a Restricted Stock Award payout, the Committee will take into account only the period of time that the Participant performed services for CEG or its Subsidiaries since the Date of Grant. "Stock" means the common stock, without par value, of CEG. "Stock Appreciation Right" means an Award granted under Section 10. "Subsidiary(ies)" means any corporation of which 20% or more of its outstanding voting stock or voting power is beneficially owned, directly or indirectly, by CEG. "Target Performance Award" means a targeted award of a specified number of Performance Units (or shares of Restricted Stock, as the context requires) which may be earned and payable (or, in the case of Restricted Stock, earned and with respect to which restrictions will lapse) based upon the performance objectives for a particular Performance Period, all as determined by the Committee. The Target Performance Award will be a factor in the Committee's ultimate determination of the Earned Performance Award. "Termination" means resignation or discharge from employment with CEG or any of its Subsidiaries except in the event of death, Disability, Retirement or Early Retirement. 3. Effective Date, Duration and Stockholder Approval. ------------------------------------------------- A. Effective Date and Stockholder Approval. This Plan has been transferred from Baltimore Gas and Electric Company (BGE) to CEG effective April 30, 1999 in connection with a share exchange between CEG and the common stockholders of BGE. The Plan was approved by a majority of the outstanding shares of common stock of BGE voted at its 1995 Annual Meeting of Stockholders, and became effective as of January 1, 1995. B. Period for Grants of Awards. Awards may be made as provided herein for a period of 10 years after January 1, 1995. C. Termination. The Plan will continue in effect until all matters relating to the payment of outstanding Awards and administration of the Plan have been settled. 3 D. Grants Outstanding. Grants outstanding at the effective time of the share exchange between CEG and the common stockholders of Baltimore Gas and Electric Company (BGE) will be converted from BGE common stock-based grants to CEG common stock-based grants. 4. Plan Administration. The Committee is the Plan Administrator and has sole ------------------- authority (except as specified otherwise herein) to determine all questions of interpretation and application of the Plan, or of the terms and conditions pursuant to which Awards are granted, exercised or forfeited under the Plan provisions, and, in general, to make all determinations advisable for the administration of the Plan to achieve its stated objective. Such determinations shall be final and not subject to further appeal. 5. Eligibility. Each officer or key employee of CEG and its Subsidiaries ----------- (including officers or employees who are members of the Board, but excluding directors who are not officers or employees) may be designated by the Committee as a Participant, from time to time, with respect to one or more Awards. No officer or employee of CEG or its Subsidiaries shall have any right to be granted an Award under this Plan. 6. Grant of Awards and Limitation of Number of Shares Awarded. The Committee ---------------------------------------------------------- may, from time to time, grant Awards to one or more Eligible Employees, provided that (i) subject to any adjustment pursuant to Section 14H, the aggregate number of shares of Stock subject to Awards under this Plan may not exceed three million (3,000,000) shares; (ii) to the extent that an Award lapses or the rights of the Participant to whom it was granted terminate, any shares of Stock subject to such Award shall again be available for the grant of an Award under the Plan; and (iii) shares delivered by CEG under the Plan may be authorized and unissued Stock, Stock held in the treasury of CEG, or Stock purchased on the open market (including private purchases) in accordance with applicable securities laws. 7. Restricted Stock Awards. ----------------------- A. Grants of Restricted Shares. One or more shares of Restricted Stock may be granted to any Eligible Employee. The Restricted Stock will be issued to the Participant on the Date of Grant without the payment of consideration by the Participant. The Restricted Stock will be issued in the name of the Participant and will bear a restrictive legend prohibiting sale, transfer, pledge or hypothecation of the Restricted Stock until the expiration of the restriction period. The Committee may also impose such other restrictions and conditions on the Restricted Stock as it deems appropriate, and will designate the grant as either a Service-Based or Performance-Based Award. Upon issuance to the Participant of the Restricted Stock, the Participant will have the right to vote the Restricted Stock, and subject to the Committee's discretion, to receive the cash dividends distributable with respect to such shares, with such dividends treated as compensation to the Participant. The Committee, in its sole discretion, may direct the accumulation and payment of distributable dividends to 4 the Participant at such times, and in such form and manner, as determined by the Committee. B. Service-Based Award. i. Restriction Period. At the time a Service-Based Restricted Stock Award is granted, the Committee will establish a restriction period applicable to such Award which will be not less than one year and not more than ten years. Each Restricted Stock Award may have a different restriction period, at the discretion of the Committee. ii. Forfeiture or Payout of Award. In the event a Participant ceases employment during a restriction period, a Restricted Stock Award is subject to forfeiture or payout (i.e., removal of restrictions) as follows: (a) Termination - the Restricted Stock Award is completely forfeited; (b) Retirement, Disability or death - payout of the Restricted Stock Award is prorated for service during the period; or (c) Early Retirement - if at the Participant's request, the payout or forfeiture of the Restricted Stock Award is determined at the discretion of the Committee, or if at CEG's request, payout of the Restricted Stock Award is prorated for service during the period; provided, however, that the Committee may modify the above if it determines at its sole discretion that special circumstances warrant such modification. Any shares of Restricted Stock which are forfeited will be transferred to CEG. Upon completion of the restriction period, all Award restrictions will expire and new certificates representing the Award will be issued (the payout) without the restrictive legend described in Section 7A. C. Performance-Based Award. i. Restriction Period. At the time a Performance-Based Restricted Stock Award is granted, the Committee will establish a restriction period applicable to such Award which will be not less than one year and not more than ten years. Each Restricted Stock Award may have a different restriction period, at the discretion of the Committee. The Committee will also establish a Performance Period. ii. Performance Objectives. The Committee will determine, no later than 90 days after the beginning of each Performance Period, the performance objectives for each Participant's Target Performance Award and the number of shares of Restricted Stock for each Target Performance Award that will be issued on the Date of Grant. Performance objectives may vary from Participant to Participant and will be based upon such performance criteria or combination of factors as the Committee deems appropriate, which may include, but not be limited to, the performance of the Participant, CEG, one or more Subsidiaries, or any combination thereof. Performance Periods may overlap and Participants may participate simultaneously with respect to Performance-Based Restricted Stock Awards for which different Performance Periods are prescribed. 5 If, during the course of a Performance Period significant events occur as determined in the sole discretion of the Committee, which the Committee expects to have a substantial effect on a performance objective during such period, the Committee may revise such objective. iii. Forfeiture or Payout of Award. As soon as practicable after the end of each Performance Period, the Committee will determine whether the performance objectives and other material terms of the Award were satisfied. The Committee's determination of all such matters will be final and conclusive. As soon as practicable after the later of (i) the date the Committee makes the above determination, or (ii) the completion of the restriction period, the Committee will determine the Earned Performance Award for each Participant. Such determination may result in forfeiture of all or some shares of Restricted Stock (if Target Performance Award performance objectives were not attained), or the issuance of additional shares of Stock (if Target Performance Award performance objectives were exceeded), and will be based upon such factors as the Committee determines at its sole discretion, but including the Target Performance Award performance objectives. In the event a Participant ceases employment during a restriction period, the Restricted Stock Award is subject to forfeiture or payout (i.e., removal of restrictions) as follows: (a) Termination - the Restricted Stock Award is completely forfeited; (b) Retirement, Disability or death - payout of the Restricted Stock Award is prorated taking into account factors including, but not limited to, service during the period; and the performance of the Participant during the portion of the Performance Period before employment ceased; or (c) Early Retirement - if at the Participant's request, the payout or forfeiture of the Restricted Stock Award is determined at the discretion of the Committee, or if at CEG's request, payout of the Restricted Stock Award is prorated taking into account factors including, but not limited to, service during the period and the performance of the Participant during the portion of the Performance Period before employment ceased; provided, however, that the Committee may modify the above if it determines at its sole discretion that special circumstances warrant such modification. Any shares of Restricted Stock which are forfeited will be transferred to CEG. With respect to shares of Restricted Stock for which restrictions lapse, new certificates will be issued (the payout) without the restrictive legend described in Section 7A. New certificates will also be issued for additional Stock, if any, awarded to the Participant because Target Performance Award performance objectives were exceeded. D. Waiver of Section 83(b) Election. Unless otherwise directed by the Committee, as a condition of receiving an Award of Restricted Stock, a Participant must waive in writing the right to make an election under Section 83(b) of the Code to report the value of the Restricted Stock as income on the Date of Grant. 8. Stock Options. ------------- 6 A. Grants of Options. One or more Options may be granted to any Eligible Employee on the Date of Grant without the payment of consideration by the Participant. B. Stock Option Agreement. Each Option granted under the Plan will be evidenced by a "Stock Option Agreement" between CEG and the Participant containing provisions determined by the Committee, including, without limitation, provisions to qualify Incentive Stock Options as such under Section 422 of the Code if directed by the Committee at the Date of Grant; provided, however, that each Incentive Stock Option Agreement must include the following terms and conditions: (i) that the Options are exercisable, either in total or in part, with a partial exercise not affecting the exercisability of the balance of the Option; (ii) every share of Stock purchased through the exercise of an Option will be paid for in full at the time of the exercise; (iii) each Option will cease to be exercisable, as to any share of Stock, at the earliest of (a) the Participant's purchase of the Stock to which the Option relates, (b) the Participant's exercise of a related Stock Appreciation Right, or (c) the lapse of the Option; (iv) Options will not be transferable by the Participant except by Will or the laws of descent and distribution and will be exercisable during the Participant's lifetime only by the Participant or by the Participant's guardian or legal representative; and (v) notwithstanding any other provision, in the event of a public tender for all or any portion of the Stock or in the event that any proposal to merge or consolidate CEG with another company is submitted to the stockholders of CEG for a vote, the Committee, in its sole discretion, may declare any previously granted Option to be immediately exercisable. C. Option Price. The Option price per share of Stock will be set by the grant, but will be not less than 100% of the Fair Market Value at the Date of Grant. D. Form of Payment. At the time of the exercise of the Option, the Option price will be payable in cash or in other shares of Stock or in a combination of cash and other shares of Stock, in a form and manner as required by the Committee in its sole discretion. When Stock is used in full or partial payment of the Option price, it will be valued at the Fair Market Value on the date the Option is exercised. E. Other Terms and Conditions. The Option will become exercisable in such manner and within such Option Period or Periods, not to exceed 10 years from its Date of Grant, as set forth in the Stock Option Agreement upon payment in full. Except as otherwise provided in this Plan or in the Stock Option Agreement, any Option may be exercised in whole or in part at any time. F. Lapse of Option. An Option will lapse upon the earlier of: (i) 10 years from the Date of Grant, or (ii) at the expiration of the Option Period set by the grant. If the Participant ceases employment within the Option Period and prior to the lapse of the Option, the Option will lapse as follows: (a) Termination - the Option will lapse on the effective date of the Termination; or (b) Retirement, Early Retirement, or Disability - the Option will lapse at the expiration of the Option Period set by the grant; provided, however, that the Committee may modify the above if it determines in its sole discretion that special circumstances 7 warrant such modification. If the Participant dies within the Option Period and prior to the lapse of the Option, the Option will lapse at the expiration of the Option Period set by the grant unless it is exercised before such time by the Participant's legal representative(s) or by the person(s) entitled to do so under the Participant's Will or, if the Participant fails to make testamentary disposition of the Option or dies intestate, by the person(s) entitled to receive the Option under the applicable laws of descent and distribution. G. Individual Limitation. In the case of an Incentive Stock Option, the aggregate Fair Market Value of the Stock for which Incentive Stock Options (whether under this Plan or another arrangement) in any calendar year are first exercisable will not exceed $100,000 with respect to such calendar year (or such other individual limit as may be in effect under the Code on the Date of Grant) plus any unused portion of such limit as the Code may permit to be carried over. 9. Performance Units. ----------------- A. Performance Units. One or more Performance Units may be earned by an Eligible Employee based on the achievement of preestablished performance objectives during a Performance Period. B. Performance Period and Performance Objectives. The Committee will determine a Performance Period and will determine, no later than 90 days after the beginning of each Performance Period, the performance objectives for each Participant's Target Performance Award and the number of Performance Units subject to each Target Performance Award. Performance objectives may vary from Participant to Participant and will be based upon such performance criteria or combination of factors as the Committee deems appropriate, which may include, but not be limited to, the performance of the Participant, CEG, one or more Subsidiaries, or any combination thereof. Performance Periods may overlap and Participants may participate simultaneously with respect to Performance Units for which different Performance Periods are prescribed. If during the course of a Performance Period significant events occur as determined in the sole discretion of the Committee which the Committee expects to have a substantial effect on a performance objective during such period, the Committee may revise such objective. C. Forfeiture or Payout of Award. As soon as practicable after the end of each Performance Period, the Committee will determine whether the performance objectives and other material terms of the Award were satisfied. The Committee's determination of all such matters will be final and conclusive. As soon as practicable after the date the Committee makes the above determination, the Committee will determine the Earned Performance Award for each Participant. Such determination may result in an increase or decrease in the number of Performance Units payable based upon such Participant's Target Performance Award, and will be based upon such factors as the Committee determines in its sole discretion, but including the Target Performance Award performance objectives. 8 In the event a Participant ceases employment during a Performance Period, the Performance Unit Award is subject to forfeiture or payout as follows: (a) Termination - the Performance Unit Award is completely forfeited; (b) Retirement, Disability or death - payout of the Performance Unit Award is prorated taking into account factors including, but not limited to, service and the performance of the Participant during the portion of the Performance Period before employment ceased; or (c) Early Retirement - if at the Participant's request, the payout or forfeiture of the Performance Unit Award is determined at the discretion of the Committee, or if at CEG's request, payout of the Performance Unit Award is prorated taking into account factors including, but not limited to, service and the performance of the Participant during the portion of the Performance Period before employment ceased; provided, however, that the Committee may modify the above if it determines in its sole discretion that special circumstances warrant such modification. D. Form and Timing of Payment. Each Performance Unit is payable in cash or shares of Stock or in a combination of cash and Stock, as determined by the Committee in its sole discretion. Such payment will be made as soon as practicable after the Earned Performance Award is determined. 10. Stock Appreciation Rights. ------------------------- A. Grants of Stock Appreciation Rights. Stock Appreciation Rights may be granted under the Plan in conjunction with an Option either at the Date of Grant or by amendment or may be separately granted. Stock Appreciation Rights will be subject to such terms and conditions not inconsistent with the Plan as the Committee may impose. B. Right to Exercise; Exercise Period. A Stock Appreciation Right issued pursuant to an Option will be exercisable to the extent the Option is exercisable; both such Stock Appreciation Right and the Option to which it relates will not be exercisable during the six months following their respective Dates of Grant except in the event of the Participant's Disability or death. A Stock Appreciation Right issued independent of an Option will be exercisable pursuant to such terms and conditions established in the grant. Notwithstanding such terms and conditions, in the event of a public tender for all or any portion of the Stock or in the event that any proposal to merge or consolidate CEG with another company is submitted to the stockholders of CEG for a vote, the Committee, in its sole discretion, may declare any previously granted Stock Appreciation Right immediately exercisable. C. Failure to Exercise. If on the last day of the Option Period, in the case of a Stock Appreciation Right granted pursuant to an Option, or the specified Exercise Period, in the case of a Stock Appreciation Right issued independent of an Option, the Participant has not exercised a Stock Appreciation Right, then such Stock Appreciation Right will be deemed to have been exercised by the Participant on the last day of the Option Period or Exercise Period. D. Payment. An exercisable Stock Appreciation Right granted pursuant to an Option will entitle the Participant to surrender unexercised the Option or any portion thereof to which the Stock Appreciation Right is attached, and to receive 9 in exchange for the Stock Appreciation Right payment (in cash or Stock or a combination thereof as described below) equal to either of the following amounts, determined in the sole discretion of the Committee at the Date of Grant: (1) the excess of the Fair Market Value of one share of Stock at the date of exercise over the Option price, times the number of shares called for by the Stock Appreciation Right (or portion thereof) which is so surrendered, or (2) the excess of the Book Value of one share of Stock at the date of exercise over the Book Value of one share of Stock at the Date of Grant of the related Option, times the number of shares called for by the Stock Appreciation Right. Upon exercise of a Stock Appreciation Right not granted pursuant to an Option, the Participant will receive for each Stock Appreciation Right payment (in cash or Stock or a combination thereof as described below) equal to either of the following amounts, determined in the sole discretion of the Committee at the Date of Grant: (1) the excess of the Fair Market Value of one share of Stock at the date of exercise over the Fair Market Value of one share of Stock at the Date of Grant of the Stock Appreciation Right, times the number of shares called for by the Stock Appreciation Right, or (2) the excess of the Book Value of one share of Stock at the date of exercise of the Stock Appreciation Right over the Book Value of one share of Stock at the Date of Grant of the Stock Appreciation Right, times the number of shares called for by the Stock Appreciation Right. The Committee may direct the payment in settlement of the Stock Appreciation Right to be in cash or Stock or a combination thereof. Alternatively, the Committee may permit the Participant to elect to receive cash in full or partial settlement of the Stock Appreciation Right, provided that (i) the Committee must consent to or disapprove such election and (ii) unless the Committee directs otherwise, the election and the exercise must be made during the period beginning on the 3rd business day following the date of public release of quarterly or year-end earnings and ending on the 12th business day following the date of public release of quarterly or year-end earnings. The value of the Stock to be received upon exercise of a Stock Appreciation Right shall be the Fair Market Value of the Stock on the trading day preceding the date on which the Stock Appreciation Right is exercised. To the extent that a Stock Appreciation Right issued pursuant to an Option is exercised, such Option shall be deemed to have been exercised, and shall not be deemed to have lapsed. E. Nontransferable. A Stock Appreciation Right will not be transferable by the Participant except by Will or the laws of descent and distribution and will be exercisable during the Participant's lifetime only by the Participant or by the Participant's guardian or legal representative. F. Lapse of a Stock Appreciation Right. A Stock Appreciation Right will lapse upon the earlier of: (i) 10 years from the Date of Grant; or (ii) at the expiration of the Exercise Period as set by the grant. If the Participant ceases employment within the Exercise Period and prior to the lapse of the Stock Appreciation Right, the Stock Appreciation Right will lapse as follows: (a) Termination - the Stock Appreciation Right will lapse on the effective date of the Termination; or (b) Retirement, Early Retirement, or Disability - the Stock Appreciation Right will lapse at the expiration of the Exercise Period set by the grant; provided, however, that the Committee may modify the above if it determines in its sole discretion that special circumstances warrant such 10 modification. If the Participant dies within the Exercise Period and prior to the lapse of the Stock Appreciation Right, the Stock Appreciation Right will lapse at the expiration of the Exercise Period set by the grant unless it is exercised before such time by the Participant's legal representative(s) or by the person(s) entitled to do so under the Participant's Will or, if the Participant fails to make testamentary disposition of the Stock Appreciation Right or dies intestate, by the person(s) entitled to receive the Stock Appreciation Right under the applicable laws of descent and distribution. 11. Dividend Equivalents. -------------------- A. Grants of Dividend Equivalents. Dividend Equivalents may be granted under the Plan in conjunction with an Option or a separately awarded Stock Appreciation Right, at the Date of Grant or by amendment, without consideration by the Participant. Dividend Equivalents may also be granted under the Plan in conjunction with Performance Units, at any time during the Performance Period, without consideration by the Participant. Dividend Equivalents will be granted under a Performance-Based Restricted Stock Award in conjunction with additional shares of Stock issued if Target Performance Award performance objectives are exceeded. B. Payment. Each Dividend Equivalent will entitle the Participant to receive an amount equal to the dividend actually paid with respect to a share of Stock on each dividend payment date from the Date of Grant to the date the Dividend Equivalent lapses as set forth in Section 11D. The Committee, in its sole discretion, may direct the payment of such amount at such times and in such form and manner as determined by the Committee. C. Nontransferable. A Dividend Equivalent will not be transferable by the Participant. D. Lapse of a Dividend Equivalent. Each Dividend Equivalent will lapse on the earlier of (i) the date of the lapse of the related Option or Stock Appreciation Right; (ii) the date of the exercise of the related Option or Stock Appreciation Right; (iii) the end of the Performance Period (or if earlier, the date the Participant ceases employment) of the related Performance Units or Performance-Based Restricted Stock Award; or (iv) the lapse date established by the Committee on the Date of Grant of the Dividend Equivalent. 12. Accelerated Award Payout/Exercise. --------------------------------- A. Change in Control. Notwithstanding anything in this Plan document to the contrary, a Participant is entitled to an accelerated payout or accelerated Option or Exercise Period (as set forth in Section 12B) with respect to any previously granted Award, upon the happening of a change in control. A change in control for purposes of this Section 12 means (i) the purchase or acquisition by any person, entity or group of persons, (within the meaning of section 13(d) or 14(d) of the 1934 Act, or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the 1934 Act) of 20 percent or more of either the outstanding shares of common 11 stock of CEG or the combined voting power of CEG's then outstanding shares of voting securities entitled to a vote generally, or (ii) the consummation of, following the approval by the stockholders of CEG of a reorganization, merger, or consolidation, in each case, with respect to which persons who were stockholders of CEG immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity's then outstanding securities, or (iii) a liquidation or dissolution of CEG or the sale of substantially all of its assets, or (iv) a change of more than one- half of the members of the Board within a 90-day period for reasons other than the death, disability, or retirement of such members. B. Amount of Award Subject to Accelerated Payout/Option Period/Exercise Period. The amount of a Participant's previously granted Award that will be paid or exercisable upon the happening of a change in control will be determined as follows: Restricted Stock Awards. The Participant will be entitled to an ----------------------- accelerated Award payout, and the amount of the payout will be based on the number of shares of Restricted Stock that were issued on the Date of Grant, prorated based on the number of months of the restriction period that have elapsed as of the payout date. Also, with respect to Performance-Based Restricted Stock Awards, in determining the amount of the payout, maximum performance achievement will be assumed. Stock Option Awards and Stock Appreciation Rights. Any previously granted ------------------------------------------------- Stock Option Awards or Stock Appreciation Rights will be immediately exercisable. Performance Units. The Participant will be entitled to an accelerated Award ----------------- payout, and the amount of the payout will be based on the number of Performance Units subject to the Target Performance Award as established on the Date of Grant, prorated based on the number of months of the Performance Period that have elapsed as of the payout date, and assuming that maximum performance was achieved. C. Timing of Accelerated Payout/Option Period/Exercise Period. The accelerated payout set forth in Section 12B will be made in cash within 30 days after the date of the change in control. The accelerated Option Period/Exercise Period set forth in Section 12B will begin on the date of the change in control, and applicable payments will be in cash. When Stock is related to the Award, the amount of cash will be determined based on the Fair Market Value of Stock on the payout or exercise date, whichever is applicable. 13. Amendment of Plan. ----------------- The Committee may at any time and from time to time alter, amend, suspend or terminate the Plan in whole or in part, except (i) no such action may be taken without stockholder approval which materially increases the benefits accruing to Participants pursuant to the Plan, materially increases the number of securities 12 which may be issued pursuant to the Plan (except as provided in Section 14H), extends the period for granting Options under the Plan or materially modifies the requirements as to eligibility for participation in the Plan; and (ii) no such action may be taken without the consent of the Participant to whom any Award was previously granted, which adversely affects the rights of such Participant concerning such Award, except as such termination or amendment of the Plan is required by statute, or rules and regulations promulgated thereunder. Notwithstanding the foregoing, the Committee may amend the Plan as desirable at the discretion of the Committee to address any issues concerning (i) Section 162(m) of the Code, or (ii) maintaining an exemption under rule 16b-3 of the 1934 Act. 14. Miscellaneous Provisions. ------------------------ A. Nontransferability. No benefit provided under this Plan shall be subject to alienation or assignment by a Participant (or by any person entitled to such benefit pursuant to the terms of this Plan), nor shall it be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or federal statute, (ii) as requested by the Participant (or by any person entitled to such benefit pursuant to the terms of this Plan), and approved by the Committee, to satisfy income tax withholding, and (iii) as requested by the Participant and approved by the Committee, to members of the Participant's family, or a trust established by the Participant for the benefit of family members. B. No Employment Right. Participation in this Plan shall not constitute a contract of employment between CEG or any Subsidiary and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person. C. Tax Withholding. CEG or a Subsidiary may withhold any applicable federal, state or local taxes at such time and upon such terms and conditions as required by law or determined by CEG or a Subsidiary. Subject to compliance with any requirements of applicable law, the Committee may permit or require a Participant to have any portion of any withholding or other taxes payable in respect to a distribution of Stock satisfied through the payment of cash by the Participant to CEG or a Subsidiary, the retention by CEG or a Subsidiary of shares of Stock, or delivery of previously owned shares of the Participant's Stock, having a Fair Market Value equal to the withholding amount. D. Fractional Shares. Any fractional shares concerning Awards shall be eliminated at the time of payment or payout by rounding down for fractions of less than one-half and rounding up for fractions of equal to or more than one-half. No cash settlements shall be made with respect to fractional shares eliminated by rounding. E. Government and Other Regulations. The obligation of CEG to make payment of Awards in Stock or otherwise shall be subject to all applicable laws, rules, and regulations, and to such approvals by any government agencies as may be required. CEG shall be under no obligation to register under the Securities Act of 1933, as amended ("Act"), any of the shares of Stock issued, delivered or paid in settlement under the Plan. If Stock awarded under the Plan 13 may in certain circumstances be exempt from registration under the Act, CEG may restrict its transfer in such manner as it deems advisable to ensure such exempt status. F. Indemnification. Each person who is or at any time serves as a member of the Committee (and each person or Committee to whom the Committee or any member thereof has delegated any of its authority or power under this Plan) shall be indemnified and held harmless by CEG against and from (i) any loss, cost, liability, or expense that may be imposed upon or reasonably incurred by such person in connection with or resulting from any claim, action, suit, or proceeding to which such person may be a party or in which such person may be involved by reason of any action or failure to act under the Plan; and (ii) any and all amounts paid by such person in satisfaction of judgment in any such action, suit, or proceeding relating to the Plan. Each person covered by this indemnification shall give CEG an opportunity, at its own expense, to handle and defend the same before such person undertakes to handle and defend it on such person's own behalf. The foregoing right of indemnification shall not be exclusive of any other rights of indemnification to which such persons may be entitled under the Charter or By-Laws of CEG or any of its Subsidiaries, as a matter of law, or otherwise, or any power that CEG may have to indemnify such person or hold such person harmless. G. Reliance on Reports. Each member of the Committee (and each person or Committee to whom the Committee or any member thereof has delegated any of its authority or power under this Plan) shall be fully justified in relying or acting in good faith upon any report made by the independent public accountants of CEG and its Subsidiaries and upon any other information furnished in connection with the Plan. In no event shall any person who is or shall have been a member of the Committee be liable for any determination made or other action taken or any omission to act in reliance upon any such report or information or for any action taken, including the furnishing of information, or failure to act, if in good faith. H. Changes in Capital Structure. In the event of any change in the outstanding shares of Stock by reason of any stock dividend or split, recapitalization, combination or exchange of shares or other similar changes in the Stock, then appropriate adjustments shall be made in the shares of Stock theretofore awarded to the Participants and in the aggregate number of shares of Stock which may be awarded pursuant to the Plan. Such adjustments shall be conclusive and binding for all purposes. Additional shares of Stock issued to a Participant as the result of any such change shall bear the same restrictions as the shares of Stock to which they relate. I. CEG Successors. In the event CEG becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which CEG will not be the surviving corporation or in which the holders of the Stock will receive securities of another corporation (in any such case, the "New Company"), then the New Company shall assume the rights and obligations of CEG under this Plan. 14 J. Governing Law. All matters relating to the Plan or to Awards granted hereunder shall be governed by the laws of the State of Maryland, without regard to the principles of conflict of laws. K. Relationship to Other Benefits. Any Awards under this Plan are not considered compensation for purposes of determining benefits under any pension, profit sharing, or other retirement or welfare plan, or for any other general employee benefit program. L. Expenses. The expenses of administering the Plan shall be borne by CEG and its Subsidiaries. M. Titles and Headings. The titles and headings of the sections in the Plan are for convenience of reference only, and in the event of any conflict, the text of the Plan, rather than such titles or headings, shall control. 15 EX-10.G 3 0003.txt GRANTOR TRUST AGREEMENT Exhibit 10(g) GRANTOR TRUST AGREEMENT Dated as of January 1, 2001 between CONSTELLATION ENERGY GROUP, INC. and CITIBANK, N.A. GRANTOR TRUST AGREEMENT CONTENTS Section 1. Establishment of Trust. 6 1.1 Trust is established with Trustee. 6 1.2 Trust is irrevocable. 7 1.3 Trust is a grantor trust. 7 1.4 Assets subject to claims of creditors. 7 1.5 Due date of Trust contributions. 8 1.6 Discretionary contributions. 8 1.7 Eligibility for Trust benefits. 8 1.8 Definition of "Required Contribution." 9 1.9 Responsibility for Required Contribution calculation. 11 1.10 Notification upon failure to made Required Contribution. 12 Section 2. Payments to Plan Participants and Their Surviving Spouses. 12 2.1 Constellation Energy required to provide Payment Schedule to Trustee. 12 2.2 Failure by Constellation Energy to provide Payment Schedule. 14 2.3 Tax withholding. 15 2.4 Determination entitlement to benefits. 16 2.5 Payment of benefits directly by Constellation Energy. 16 2.6 Authorization for Trustee to defer payments. 17 2.7 Determination of insufficient assets. 18 2.8 Notification of insufficiency. 19 2.9 Restoration of discontinued or reduced payments. 19 2.10 Determination of immediate taxation. 20 2.11 Reduction of future benefits following immediate taxation. 20 Section 3. Trustee Responsibility Regarding Payments to Trust Beneficiary When Constellation Energy Is Insolvent. 21 3.1 Payments cease when Constellation Energy is Insolvent. 21 3.2 Assets subject to claims of creditors. 21 3.2(a) Duty to inform Trustee of Constellation Energy's Insolvency. 21 3.2(b) Trustee's responsibility to cease payments. 22 3.2(c) Trustee reliance on Insolvency evidence. 22 3.2(d) Trustee holds assets for general creditors. 23 3.2(e) Authority to resume payments. 23 3.3 Restoration of discontinued payments. 24 Section 4. Payments to Constellation Energy. 24 4.1 Return or diversion of Trust assets. 24 4.2 Distribution of excess Trust assets to Constellation Energy. 25
4.3 Distribution of excess Trust assets following a Change of Control. 25 Section 5. Investment Authority. 25 5.1 No investment in Constellation Energy stock. 25 5.2 Acknowledgement of investment guidelines. 26 5.3 Constellation Energy may appoint investment advisor. 26 5.4 Constellation Energy may transfer life insurance to Trust. 27 Section 6. Disposition of Income. 28 Section 7. Accounting by Trustee. 28 7.1 Trustee provides monthly accounting to Constellation Energy. 28 7.2 Deemed approval of accounting by Constellation Energy. 29 7.3 Tax returns. 30 7.4 Right of Trustee to judicial settlement of accounts. 30 Section 8. Responsibility of Trustee. 31 8.1 Prudency standard for Trustee. 31 8.2 Indemnification of Trustee. 31 8.3 Powers of Trustee. 32 8.4 Additional powers of Trustee. 33 8.5 Trustee prohibited from carrying on business through Trust. 35 Section 9. Compensation and Expenses of Trustee 35 9.1 Trustee's fees. 35 9.2 Taxes on Trust income. 35 Section 10. Resignation and Removal of Trustee. 36 10.1 Resignation of Trustee. 36 10.2 Removal of Trustee. 36 10.3 Removal of Trustee after Change of Control. 36 10.4 Resignation of Trustee after Change of Control. 36 10.5 Transfer of assets after resignation or removal of Trustee. 36 10.6 Appointment of successor Trustee. 37 Section 11. Appointment of Successor. 37 11.1 Appointment of successor after removal or resignation of Trustee. 37 11.2 Appointment of successor Trustee following Change of Control. 37 11.3 Responsibility of successor Trustee. 38 11.4 Trustee provides written account after removal or resignation. 38
12.1 Amendments to Trust. 38 12.2 Termination date of Trust. 39 12.3 Trust termination after participant approval. 39 12.4 Amendment following Change of Control. 39 Section 13. Miscellaneous. 40 13.1 Provisions prohibited by law. 40 13.2 Alienation clause. 40 13.3 Trust under New York law. 40 13.4 Definitions and plurals. 40 13.5 Definition of Change of Control. 41 13.6 Certification of authority to act. 41 13.7 Indemnification of Trustee. 43 13.8 Authority of Trust Agreement. 44 13.9 Addresses for Trustee and Constellation Energy. 44 Section 14. Effective Date. 45
GRANTOR TRUST AGREEMENT Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. THIS AGREEMENT dated as of January 1, 2001, by and between Constellation Energy Group, Inc., a Maryland corporation, or its successor ("Constellation Energy") and Citibank, N. A., a national banking association as trustee for the trust created hereby ("Trustee"). WITNESSETH THAT: WHEREAS, Constellation Energy has adopted and amended the Constellation Energy Group, Inc. Senior Executive Supplemental Plan and the Constellation Energy Group, Inc. Supplemental Pension Plan(formerly the Constellation Energy Group, Inc. Executive Benefits Plan) ("Plans"); and WHEREAS, Constellation Energy has incurred or expects to incur liability under the terms of such Plans for nonqualified supplemental pension retirement benefits with respect to the individuals participating in such Plans; and WHEREAS, Constellation Energy wishes to adopt the trust ("Trust") and to contribute to the Trust assets that shall be held therein, subject to the claims of Constellation Energy's creditors in the event of Constellation Energy's Insolvency, as defined in Section 3.1 hereof, until paid to Plan participants and their surviving spouses, as defined in Section 6 of the Plans, in such manner and at such times as specified in the Plans; and WHEREAS, it is the intention of the parties that this Trust shall constitute an unfunded arrangement and shall not affect the status of the Plans as unfunded plans maintained for the purpose of providing nonqualified supplemental pension retirement benefits for a select group of management or highly compensated employees, for purposes of Title I of the Employee Retirement Income Security Act of 1974; and WHEREAS, it is the intention of Constellation Energy to make contributions to the Trust to provide a source of funds to assist in meeting Constellation Energy's liabilities under the Plans; NOW, THEREFORE, the parties do hereby establish the Trust and agree that the Trust shall be comprised, held and disposed of as follows: Section 1. Establishment of Trust. 1.1 Constellation Energy hereby adopts and establishes with Trustee the Trust consisting of such sums of cash and other property, including collateral assignments of interests in certain split dollar life insurance policies, (the "principal"), that currently constitute the Trust and as from time to time shall be paid or delivered to Trustee to be held, administered, and disposed of by Trustee as provided in this Trust Agreement. The principal of the Trust and any earnings thereon (the "Trust assets") shall be held by Trustee and shall be dealt with in accordance with the provisions of this Trust Agreement until all payments required by this Trust Agreement have been made. 1.2 The Trust hereby established shall be irrevocable. 1.3 The Trust is intended to be a grantor trust, of which Constellation Energy is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, and shall be construed accordingly. 1.4 The Trust assets shall be held separate and apart from other funds of Constellation Energy and shall be used exclusively for the uses and purposes of Plan participants, their surviving spouses, and Constellation Energy's general creditors as herein set forth. Plan participants and their surviving spouses shall have no preferred claim on, or any beneficial ownership interest in, any Trust assets. Any rights created under the Plans and this Trust Agreement shall be mere unsecured contractual rights of Plan participants and their surviving spouses against Constellation Energy. Any Trust assets will be subject to the claims of Constellation Energy's general creditors under federal and state law in the event of Insolvency, as defined in Section 3.1 hereof. 1.5 By August 31, 1994, for the Plan year 1993, BGE was required to irrevocably contribute cash or other property to the Trust in an amount equal to 50% of the Required Contribution, as defined in Section 1.9 hereof. By April 30 of the year following each of the Plan years 1994-1999, BGE was required to irrevocably contribute additional cash or other property to the Trust in an amount equal to 100% of the Required Contribution. By May 31st of the year following each of the Plan years 2000-2002, Constellation Energy shall be required to irrevocably contribute cash or other property to the Trust in an amount equal to 100% of the Required Contribution. 1.6 Constellation Energy, in its sole discretion, may at any time, or from time to time, make additional contributions of cash or other property to the Trust to augment the Trust assets to be held, administered and disposed of by Trustee as provided in this Trust Agreement. Neither Trustee nor any Plan participant or surviving spouse shall have any right to compel such additional contributions. 1.7 Plan participants or their surviving spouses shall be eligible to receive benefits under this Trust Agreement only if the Plan participant was an employee of Constellation Energy or a subsidiary in Constellation Energy's controlled group ("Employee") as well as a Plan participant as of the end of any Plan year for which a contribution was required pursuant to Section 1.5 hereof, or as of the end of any Plan year for which a contribution was made pursuant to Section 1.6, except that for the Plan year 1993, Plan participants or their surviving spouses shall be eligible to receive benefits under this Trust Agreement only if the Plan participant was an Employee as well as a Plan participant as of the first day of 1993. 1.8 "Required Contribution," for purposes of the contribution requirements as set forth in Section 1.5 hereof, means the sum of (1), (2), (3), (4) and (5) below computed as indicated herein, less the fair market value of the Trust ---- assets at the end of the Plan year for which the contribution is required. (1) For Plan participants eligible to receive benefits under this Trust Agreement pursuant to Section 1.7 hereof, who were also Employees as of the end of the Plan year for which the contribution is required (except Employees entitled to lump sum payments as indicated under Section 1.8(4) hereof) and who were not eligible for early retirement under the Plans at the end of the Plan year for which the contribution is required, an amount equal to the present value of an annuity including the estimated present value of post retirement supplemental survivor annuity benefits under the Plans commencing effective with the month in which the participant becomes age 65 using (i) the net accrued benefit as computed under the Plans (without regard to age and Credited Service eligibility requirements), expressed as a monthly amount, (ii) an interest rate equal to the lesser of 8% or 95% of the Interest Rate under the Plans, and (iii) the Mortality Table. (2) For Plan participants eligible to receive benefits under this Trust Agreement pursuant to Section 1.7 hereof, who were also Employees as of the end of the Plan year for which the contribution is required (except Constellation Energy Employees entitled to lump sum payments as indicated under Section 1.8(4) hereof) and who were eligible for early retirement under the Plans as of the end of the Plan year for which the contribution is required, an amount equal to the present value of an annuity including the present value of post retirement supplemental survivor annuity benefits under the Plans commencing effective with the first month following the Plan year for which the contribution is required using (i) the net accrued benefit as computed under the Plans, expressed as a monthly amount, (ii) an interest rate equal to the lesser of 8% or 95% of the Interest Rate under the Plans, and (iii) the Mortality Table. (3) For Plan participants or their surviving spouses who are eligible to receive benefits under this Trust Agreement pursuant to Section 1.7 hereof who were also receiving a retirement benefit under the Plans in the form of a monthly payment as of the end of the Plan year for which the contribution is required, an amount equal to the present value of an annuity as computed under (2)(i),(ii), and (iii) above except that the interest rate used to compute the present value under (ii) shall be 8%. (4) For all Plan participants eligible to receive benefits under this Trust Agreement pursuant to Section 1.7 hereof who are also entitled under Section 5 of the Plans to receive a lump sum payment at the later of age 55 or upon separation from service as of the end of the Plan year for which the contribution is required, an amount equal to the present value of an annuity as computed under (1) above. (5) In the event there has been a reduction or discontinuance of payments pursuant to Sections 2.6, 2.7, or Section 3 hereof, an amount equal to the total amount of any previously reduced or discontinued payments to Plan participants and their surviving spouses, less the aggregate amount of any payments made to Plan participants and their surviving spouses by Constellation Energy or BGE in lieu of such payments, plus interest computed pursuant to Section 2.9 hereof on the net aggregate amount. 1.9 Constellation Energy shall have sole responsibility for providing to Trustee the determination and calculation of the Required Contribution which shall be determined and calculated by the actuary of the Pension Plan of Constellation Energy Group, Inc. Trustee shall have no responsibility with respect to such determination and calculation including the responsibility to verify (i) the accuracy of such calculation or (ii) compliance by Constellation Energy with the terms of Section 1 hereof, except as provided in Section 1.11 hereof. Trustee shall have no duty, obligation or responsibility to bring any action or proceeding to enforce the collection of the Required Contribution from Constellation Energy. 1.10 In the event Constellation Energy fails to make the Required Contribution to the Trust by the dates specified in Section 1.5 hereof, Trustee shall notify Constellation Energy of such failure by the 15th day of the month following the month in which the contribution was required. Such notification shall stipulate that Constellation Energy may correct the failure to contribute by the last day of the month following the month in which the contribution was required (the "Required Contribution correction date"). Trustee shall notify the Plan participants or their surviving spouses shown on the most recent Payment Schedule, as defined in Section 2.1 hereof, provided by Constellation Energy to Trustee, in the event Constellation Energy fails to make the Required Contribution by the Required Contribution correction date. Trustee shall make such notification no later than 15 days following the Required Contribution correction date. Section 2. Payments to Plan Participants and Their Surviving Spouses. 2.1 By May 31 of the year following each Plan year until termination of the Trust under the provisions of Section 12 hereof, and at other times as reasonably requested by Trustee including such times as Trustee is notified in writing of the death of a Plan participant or surviving spouse eligible to receive benefits under this Trust Agreement, Constellation Energy shall deliver to Trustee a schedule, substantially in the format of Exhibit A hereof, and any other necessary documentation (such schedule and other documentation being referred to for this purpose as the "Payment Schedule") that indicates the Plan benefit amounts currently payable in respect of each Plan participant (and his or her surviving spouse), the form in which such amount is to be paid (as provided for or available under the Plans), the time of commencement for payment of such amounts, whether the Plan participant is receiving such payment as a result of an entitlement event (as defined in Section 5(c) of the Plans), the present value of the future benefits payable to Plan participants and their surviving spouses under the terms of this Trust Agreement computed as under Section 1.8 (1), (2), (3), and (4) hereof, and the Required Contribution computed pursuant to Section 1.8 hereof. Plan participants or their surviving spouses shall be included on the Payment Schedule and shall be eligible for benefits under this Trust Agreement pursuant to Section 1.7 hereof only to the extent contributions to the Trust were required under Section 1.5 hereof, or for which a contribution was made by Constellation Energy to the Trust pursuant to Section 1.6 hereof. A modified Payment Schedule shall be delivered by Constellation Energy to Trustee upon the occurrence of any event, such as early retirement of a Plan participant or an entitlement event, as defined in Section 5(c) of the Plans, requiring a modification of the Payment Schedule or a modified Payment Schedule. Constellation Energy shall cause the Payment Schedule which Constellation Energy shall provide to Trustee to be prepared by the actuary for the Pension Plan of Constellation Energy Group, Inc. Except as otherwise provided in Sections 2.5 through 2.11 hereof, Trustee shall make payments to Plan participants and their surviving spouses in accordance with such Payment Schedule, and shall act only upon such written direction and shall have no duty to determine the rights of any person under this Trust Agreement or under the Plans or to inquire into the right or power of Constellation Energy to direct or not direct any such payment and shall be authorized to rely on the Payment Schedule most recently provided to Trustee by Constellation Energy. 2.2 In the event Constellation Energy fails to deliver the Payment Schedule to Trustee by the date specified in Section 2.1 hereof, Trustee shall notify Constellation Energy of such failure by the 15th day of the month following the month in which the Payment Schedule was required to be delivered to Trustee. Such notification shall stipulate that Constellation Energy may correct the failure by the last day of the month following the month in which the Payment Schedule was required to be delivered to Trustee (the "Payment Schedule correction date"). Trustee shall notify the Plan participants or their surviving spouses shown on the most recent Payment Schedule provided by Constellation Energy to Trustee in the event Constellation Energy fails to deliver the Payment Schedule to Trustee by the Payment Schedule correction date. Trustee shall make such notification no later than 15 days following the Payment Schedule correction date If Constellation Energy fails to deliver the Payment Schedule to Trustee by the date specified in Section 2.1 hereof, Trustee shall make payments to Plan participants and their surviving spouses, except as otherwise provided in Sections 2.5 through 2.11 hereof, in accordance with the Payment Schedule most recently provided to Trustee by Constellation Energy (or prior to May 31, 2000, by BGE). Within a reasonable period of time after Constellation Energy delivers the updated Payment Schedule to Trustee, Trustee shall pay all amounts due to the Plan participants and their surviving spouses for the period during which Trustee relied on the previous Payment Schedule to the extent such amounts have not been paid by Trustee under the previous Payment Schedule or by Constellation Energy pursuant to Sections 2.5 through 2.11 hereof. Such amounts paid by Trustee shall include interest computed at an 8% per annum rate from the date the payments were due under the Plans to the first day of the month in which such amount was paid. 2.3 Trustee shall make provision for the reporting and withholding of any federal, state or local taxes that may be required to be withheld with respect to the payment of benefits from the Trust and shall pay amounts withheld to the appropriate taxing authorities or determine that such amounts have been reported, withheld and paid by Constellation Energy, provided, however, that Constellation Energy shall be required to provide Trustee with all information reasonably necessary for Trustee to perform such withholding. 2.4 The entitlement of Plan participants and their surviving spouses to benefits under the Plans shall be determined by Constellation Energy or such party as it shall designate under the Plans, and any claim for such benefits shall be considered and reviewed under the procedures set out in the Plans. Except as provided in Section 2.7 hereof, Trustee shall have no responsibility to determine such entitlements or to verify the accuracy of their determination or to review or supervise the review of claims for benefits. 2.5 Constellation Energy may make payment of benefits directly to Plan participants and their surviving spouses as they become due in accordance with the most recent Payment Schedule provided by Constellation Energy to Trustee. Constellation Energy shall notify Trustee of its decision to make payment of benefits prior to the time amounts are payable to Plan participants and their surviving spouses by indicating such intent on the Payment Schedule provided by Constellation Energy to Trustee pursuant to Section 2.1 or by separate written notification. Constellation Energy shall provide Trustee with documentation substantiating that such payments were made no later than the last day of the month in which such payments were due in accordance with the most recent Payment Schedule provided by Constellation Energy to Trustee. If such documentation is not provided, Trustee is authorized to make such payments directly to Plan participants and their surviving spouses. In addition, if the Trust assets are insufficient to make payments of benefits in accordance with the most recent Payment Schedule provided by Constellation Energy to Trustee, or are not available to make such payments because all or part of the Trust assets are invested in collateral assignments of certain split dollar life insurance policies, Constellation Energy shall pay the balance of each such payment to the Plan participant or their surviving spouse as it falls due. Trustee shall notify Constellation Energy of such insufficiency or unavailability as specified in Sections 2.6 and 2.8 hereof. 2.6 Where Trustee is required to make payments from the Trust according to the most recent Payment Schedule and Constellation Energy does not make payments in lieu of such payments as provided under Section 2.5 hereof, and Trustee is unable to make the required payments because all or part of the Trust assets are invested in the collateral assignment portion of certain split dollar life insurance policies, Trustee is authorized to defer the required payments until cash is available to make the required payments under the terms of this Trust Agreement. 2.7 A determination of insufficiency of Trust assets shall be made with respect to the end of each Plan year after receipt by the Trustee of the Payment Schedule prepared with respect to such Plan year or the most recent Payment Schedule in the event Constellation Energy fails to deliver the Payment Schedule to Trustee by the date specified in Section 2.1 hereof. The Trust assets will be deemed to be insufficient to make payments of benefits in accordance with the terms of such Payment Schedule if the market value of the Trust assets at the end of the Plan year for which the determination is being made plus the Required Contribution actually made with respect to such Plan year is less than the present value of the future benefits as shown on the most recent Payment Schedule. In determining the market value of collateral assignments of interests in split dollar life insurance policies held by the Trust, Trustee may rely on the valuation provided by the insurance carrier who issued such policies, or the broker administering such policies. In the event of such insufficiency and to the extent Constellation Energy does not make payments directly to Plan participants or their surviving spouses as provided under Section 2.5 hereof, any payment made from the Trust will be reduced by multiplying such payment by a fraction, the numerator of which shall be the value of all cash and other property held by the Trust and the denominator of which shall be the aggregate present value of all benefits under the Plans as shown on the most recent Payment Schedule. 2.8 If the Trust assets are insufficient to make payments of benefits in accordance with the most recent Payment Schedule, Trustee shall notify Constellation Energy of such insufficiency by May 15 of the year following the Plan year with respect to which the insufficiency has been determined. Such notification shall stipulate that Constellation Energy may correct the insufficiency by May 31 of the year following the Plan year with respect to which the insufficiency has been determined (the "insufficiency correction date"). Trustee shall notify the participants or their surviving spouses shown on the most recent Payment Schedule provided by Constellation Energy to Trustee in the event Constellation Energy fails to correct the insufficiency by the insufficiency correction date. Trustee shall make such notification no later than 15 days following the insufficiency correction date and shall proceed to reduce any payment made from the Trust in the manner specified in Section 2.7 hereof as soon as practicable. 2.9 If Trustee reduces or discontinues the payment of benefits from the Trust pursuant to Section 2.6 and 2.7 hereof and the Trust assets subsequently become sufficient to pay all or part of the previously reduced or discontinued benefits, the first payment following thereafter shall include the aggregate of all payments due to Plan participants and their surviving spouses under the terms of this Trust Agreement for the period of such reduction or discontinuance to the extent Trust assets are available, less the aggregate amount of any payments made to Plan participants and their surviving spouses by Constellation Energy in lieu of the payments provided for hereunder during any such period of reduction or discontinuance. In such event where Trust assets are sufficient to pay only a part of the previously reduced or discontinued benefits, amounts relating to the earliest payments reduced or discontinued shall be paid before all other amounts due under this Trust Agreement. Such payments shall also include interest computed at an 8% per annum rate on the net aggregate amount of all payment reductions from the date the payments were due under the Plans to the first day of the month in which such net aggregate amount was paid. 2.10 In the event there is a final judicial determination or a final determination by the Internal Revenue Service that the Plan participants and their surviving spouses are subject to any tax with respect to any amounts held under the terms of the Trust, then Trustee shall make payments from the Trust to such Plan participants and their surviving spouses in such amounts as set forth in such final determination for the purpose of paying federal taxes and interest and any penalties thereon which such Plan participants and their surviving spouses incur arising out of such determination. Trustee's decision as to whether a final determination has occurred shall be binding and conclusive on all Plan participants and their surviving spouses. 2.11 Any payment from the Trust, as provided in Section 2.10 hereof, excluding interest and penalties paid with respect to federal taxes, shall reduce the benefits payable under the Plans of those participants and their surviving spouses on whose behalf such payments are made. It shall be the responsibility of Constellation Energy to determine or cause to be determined by the actuary for the Pension Plan of Constellation Energy Group, Inc. the amount of such reduction and to provide Trustee with an updated Payment Schedule to reflect any such reduction made hereunder. Trustee shall have no duty to verify any calculations provided by Constellation Energy under this Section 2.11. Section 3. Trustee Responsibility Regarding Payments to Trust Beneficiary When Constellation Energy Is Insolvent. 3.1 Trustee shall cease payment of benefits to Plan participants and their surviving spouses if Constellation Energy is Insolvent. Constellation Energy shall be considered Insolvent for purposes of this Trust Agreement if (i) Constellation Energy makes a voluntary filing under the United States Bankruptcy Code, or (ii) Constellation Energy is subject to a pending involuntary proceeding as a debtor under the United States Bankruptcy Code. 3.2 At all times during the continuance of this Trust, as provided in Section 1.4 hereof, the Trust assets shall be subject to claims of general creditors of Constellation Energy under federal and state law as set forth below. 3.2(a) The Board of Directors of Constellation Energy and the Chief Executive Officer of Constellation Energy shall have the duty to inform Trustee in writing of Constellation Energy's Insolvency. If a person claiming to be a creditor of Constellation Energy alleges in writing to Trustee that Constellation Energy has become Insolvent, Trustee shall determine whether Constellation Energy is Insolvent and, pending such determination, Trustee shall discontinue payment of benefits to Plan participants and their surviving spouses. 3.2(b) Until receipt of a notice of Insolvency as set forth above, Trustee shall be under no obligation and shall have no responsibility to suspend payments hereunder and hold the Trust assets for the benefit of Constellation Energy's general creditors. Trustee shall not be deemed to have notice or knowledge of facts or events in public records or received by departments or divisions of Trustee bank other than the Investor Services division of Trustee bank. Trustee shall not have any liability to any party for making any payments or withholding any payments pursuant to court order or request from trustee in bankruptcy or receivership pursuant to notice of Insolvency as provided above. 3.2(c) Unless Trustee has actual knowledge of Constellation Energy's Insolvency, or has received notice from Constellation Energy or a person claiming to be a creditor alleging that Constellation Energy is Insolvent, Trustee shall have no duty to inquire whether Constellation Energy is Insolvent. Trustee may in all events rely on such evidence concerning Constellation Energy's solvency as may be furnished to Trustee and that provides Trustee with a reasonable basis for making a determination concerning Constellation Energy's solvency. 3.2(d) If at any time Trustee has determined that Constellation Energy is Insolvent, Trustee shall discontinue payments to Plan participants and their surviving spouses and shall hold the Trust assets for the benefit of Constellation Energy's general creditors. Nothing in this Trust Agreement shall in any way diminish any rights of Plan participants and their surviving spouses to pursue their rights as general creditors of Constellation Energy with respect to benefits due under the Plans or otherwise. 3.2(e) Trustee shall resume the payment of benefits to Plan participants and their surviving spouses in accordance with Section 2 of this Trust Agreement only after Trustee has determined that Constellation Energy is not Insolvent (or is no longer Insolvent). Where Constellation Energy is subject to a pending proceeding as a debtor under the United States Bankruptcy Code, Trustee shall resume payment when such proceeding is dismissed. In all other cases, Trustee shall have no obligation to so resume payment until it shall have received an unqualified opinion of a certified public accountant that Constellation Energy is no longer Insolvent and an opinion of counsel that there is no legal prohibition to resuming payment hereunder. 3.3 If Trustee discontinues the payment of benefits from the Trust pursuant to Section 3.2 hereof and subsequently resumes such payments, the first payment following such discontinuance shall include the aggregate amount of all payments due to Plan participants and their surviving spouses under the terms of this Trust Agreement for the period of such discontinuance, less the aggregate amount of any payments made to Plan participants and their surviving spouses by Constellation Energy or BGE in lieu of the payments provided for hereunder during any such period of discontinuance plus interest computed as under Section 2.9 hereof on the net aggregate amount of all payments from the date the payments were due under the Plans to the first day of the month in which such net aggregate amount was paid. Constellation Energy shall cause to be determined and calculated by the actuary of the Pension Plan of Constellation Energy Group, Inc. such net aggregate amount, which determination shall be conclusive for Constellation Energy, Trustee, and all Plan participants and their surviving spouses. Section 4. Payments to Constellation Energy. 4.1 Except as provided in Sections 3.2 and 4.2 hereof, Constellation Energy shall have no right or power to direct Trustee to return to Constellation Energy or to divert to others any of the Trust assets before all payments of benefits have been made to Plan participants and their surviving spouses in accordance with the most recent Payment Schedule provided by Constellation Energy to Trustee and the terms of this Trust Agreement. 4.2 In the event the market value of Trust assets as of the end of a Plan year exceeds 120 percent of the present value of future benefits as shown on the Payment Schedule for such Plan year, plus the amount of any payments as computed under Section 1.9(5) hereof as of the end of such Plan year, then Constellation Energy may, in its sole discretion, direct Trustee in writing to distribute such excess Trust assets, in whole or in part, to Constellation Energy provided such distribution does not contravene any provision of law. Trustee shall have no responsibility to determine the propriety of any such direction. 4.3 Notwithstanding Section 4.2 hereof, Constellation Energy may not direct Trustee to distribute such excess Trust assets for 2 years from the date a Change of Control is deemed to occur under Section 13.5 hereof. Section 5. Investment Authority. 5.1 In no event may Trustee invest in securities (including stock or rights to acquire stock) or obligations issued by Constellation Energy or BGE, other than a de minimis amount held in common investment vehicles in which Trustee invests. All rights associated with the Trust assets shall be exercised by Trustee, and shall in no event be exercisable by or rest with Plan participants and their surviving spouses; provided that Constellation Energy may at any time, upon delivery of written notice to Trustee, terminate Trustee's authority over the Trust assets. 5.2 Constellation Energy shall submit to Trustee investment guidelines which shall be acknowledged by Trustee in writing. The Trust assets shall be held, invested and reinvested by Trustee upon written direction of Constellation Energy and only in accordance with the investment guidelines most recently acknowledged by Trustee. Constellation Energy shall direct Trustee to invest or reinvest from time to time the Trust assets (taking into account, among other things, anticipated cash requirements for benefits under the Plans); provided, however, that pending receipt of investment directions or guidelines from Constellation Energy or pending the acknowledgement by Trustee of such investment guidelines, the Trust assets may be held in interest bearing cash accounts maintained by Trustee; and provided, however, that Trustee shall not be liable for any failure to maximize the income earned on the Trust assets, or for any loss suffered by the Trust, as a result of its investment or reinvestment of the Trust assets in accordance with 1) directions received by Trustee from Constellation Energy, or 2) the investment guidelines as acknowledged by Trustee. 5.3 Constellation Energy may, in its sole discretion, appoint an investment manager or managers to manage (including the power to acquire and dispose of) any Trust assets. Trustee may rely on direction of such investment manager upon receipt of written direction from Constellation Energy and shall be entitled to rely on such direction until revoked in writing by Constellation Energy. Trustee shall not be liable for the acts or omissions of such investment manager or managers, unless Trustee participates knowingly in, or knowingly undertakes to conceal, an act or omission of such investment manager, knowing that such act or omission is a breach of its or the investment manager's fiduciary duty. Trustee is under no obligation to review, inquire into or examine the acts or omissions of any such investment manager. Trustee shall have the duty to inform Constellation Energy in the event Trustee becomes aware of any such acts or omissions. Trustee shall not be under an obligation to invest or otherwise manage Trust assets which are subject to the management of the investment manager. 5.4 Constellation Energy reserves the right to transfer to the Trust in satisfaction of the contribution requirements as set forth in Section 1.5 hereof, life insurance, annuity policies or contracts on or for the life of any Plan participant, or to direct Trustee to purchase any such policies or contracts on or for the life of any such Plan participant out of the Trust assets. Any such policy or contract shall be a Trust asset subject to the claims of Constellation Energy's creditors in the event of Insolvency, as defined in Section 3.1 hereof. The proceeds, dividends, or distributions of cash value paid with respect to any life insurance policy or contract held in the Trust shall be paid to the Trust. Trustee shall be under no duty to question any direction of Constellation Energy or to review the form of any policies or contracts or the selection of the issuer thereof, or to make suggestions to Constellation Energy with respect to the form of such policies or contracts or to the issuer thereof. Section 6. Disposition of Income. During the term of this Trust, all income received by the Trust, net of expenses and taxes, shall be accumulated and reinvested, until otherwise required for disbursement under the terms of this Trust Agreement. Section 7. Accounting by Trustee. 7.1 Trustee shall keep accurate and detailed records of all investments, receipts, disbursements, and all other transactions required to be made, including such specific records as shall be agreed upon in writing between Constellation Energy and Trustee. Within 15 days following the close of each calendar month and within 90 days after the removal or resignation of Trustee, Trustee shall deliver to Constellation Energy a written account of its administration of the Trust pursuant to terms of this Trust Agreement during such year or during the period from the close of the last preceding year to the date of such removal or resignation, setting forth all investments, receipts, disbursements and other transactions effected by it, including a description of all securities and investments purchased and sold with the cost or net proceeds of such purchases or sales (accrued interest paid or receivable being shown separately), and showing all cash, and the cost and market value of all securities and other property held in the Trust at the end of such year or as of the date of such removal or resignation, as the case may be. In the event the insurance carrier who issued the insurance policies which are held by or collaterally assigned to the Trust or the broker who administers such policies does not timely provide Trustee with the market value of such insurance policies or collateral assignments, Trustee shall provide to Constellation Energy written accounts under this Section 7.1 containing all valuations except such insurance valuations. As soon as practicable following the receipt of the market valuations from the carrier or the broker, Trustee shall provide Constellation Energy with written accounts containing such insurance valuations. 7.2 Unless Constellation Energy shall have filed with Trustee written exceptions to any such statement or account delivered by Trustee pursuant to Section 7.1 hereof within 90 days after receipt of such statement or account, Constellation Energy shall be deemed to have approved such statement or account, and in such case or upon the written approval by Constellation Energy of any such statement or account, Trustee shall be forever released and discharged with respect to all matters and things embraced in such statement or account as though it had been settled by a decree of a court of competent jurisdiction in an action or proceeding to which Constellation Energy or persons having any beneficial interest in the Trust were parties. 7.3 Constellation Energy shall prepare and file such tax returns and other reports as may be required for the Trust, with any taxing authority or any other government authority and shall provide Trustee with copies of such returns and reports as soon as practicable following the date of filing. Trustee shall provide to Constellation Energy such information, to the extent not already provided through written accounts delivered to Constellation Energy pursuant to Section 7.1, as is necessary for Constellation Energy to prepare and file such tax returns and other reports. 7.4 Nothing contained in this Trust Agreement or in the Plans shall deprive Trustee of the right to have a judicial settlement of its accounts. In any proceeding for a judicial settlement of the accounts of Trustee or for instruction in connection with the Trust assets, the only necessary party thereto in addition to Trustee shall be Constellation Energy. If Trustee so elects, it may bring in as a party any other person or persons. No person interested in the Trust assets, other than Constellation Energy, shall have a right to compel an accounting, judicial or otherwise, by Trustee and each such person shall be bound by all accountings as herein provided, as if the account had been settled by decree of a court of competent jurisdiction in an action or proceeding to which such person was a party. Section 8. Responsibility of Trustee. 8.1 Trustee shall act with the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, provided, however, that Trustee shall incur no liability to any person for any action taken pursuant to a direction, request or approval given by Constellation Energy (or investment manager designated pursuant to terms hereof) which is contemplated by, and in conformity with, the terms of this Trust Agreement and is given in writing by Constellation Energy. 8.2 Trustee need not engage in any litigation, arbitration or administrative proceeding related to this Trust Agreement unless first indemnified to its reasonable satisfaction by Constellation Energy unless such litigation, arbitration or administrative proceeding is prompted by an allegation that Trustee has breached its duties undertaken pursuant to this Trust Agreement. If Trustee proceeds to engage in any such litigation, arbitration or administrative proceeding and is not so indemnified, all reasonable costs of Trustee including reasonable attorney's fees incurred pursuant to such action shall be charged against and paid from the Trust assets, except when the claim relates to an allegation that Trustee has breached its duties in which case Trustee shall be responsible for such costs. Trustee may consult with any legal counsel, including, without limitation, counsel to Constellation Energy or Trustee's own independent counsel, to assist Trustee in the management and administration of the Trust or with respect to (a) the meaning or construction of the terms of this Trust Agreement, (b) its obligations or duties hereunder, (c) any act which Trustee should take or omit hereunder, (d) any action or proceeding, or (e) any question of law. In any action taken or omitted by Trustee in good faith pursuant to the advice of such counsel, Constellation Energy shall indemnify and hold Trustee harmless against reasonable litigation expenses and attorney's fees occasioned by such action; except when Trustee acted or omitted to act upon the advice of counsel other than counsel to Constellation Energy. 8.3 Trustee shall have, without exclusion, all powers conferred on trustees by applicable law, unless expressly provided otherwise herein, provided, however, that if an insurance policy is held as an asset of the Trust, Trustee shall have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor Trustee, or to loan to any person the proceeds of any borrowing against such policy. Trustee, as assignee under split dollar life insurance policies, may exercise the right to obtain policy loans in accordance with the terms of the collateral assignment document. 8.4 In executing its duties, obligations and responsibilities as herein provided, and in addition to those powers given by law, Trustee shall have the power, in its sole discretion: (a) to collect and receive any and all money and other property due to the Trust and to give full discharge therefor; (b) to settle, compromise or submit to arbitration any claims, debts or damages due to or owing to or from the Trust; to commence or defend suits or legal proceedings to protect any interest of the Trust; and to represent the Trust in all suits or legal proceedings in any court or before any other body or tribunal; (c) if specifically instructed by Constellation Energy, to provide benefits through the purchase of individual or group annuity or life insurance contracts issued by insurance companies licensed to do business in the State of New York; (d) if specifically instructed by Constellation Energy, to act as agent for Constellation Energy to perform multiple services for the Plans, its participants and beneficiaries and to receive and withdraw from the Trust assets reasonable compensation therefor; (e) to engage accountants or other advisors as Trustee may deem necessary to control and manage the Trust assets and to carry out the purposes of this Trust Agreement; (f) subject to Section 5 hereof, to invest and reinvest the Trust assets without distinction between principal and income in any form of property not prohibited by law including, without limitation on the amount which may be invested therein, any common or group trust fund operated by Trustee or in demand deposits of Trustee; (g) to hold cash uninvested in an amount considered necessary and practical for proper administration of the Trust and/or to deposit the same with any banking, savings or similar financial institution supervised by the United States or any State, including Trustee's own banking department; and (h) to perform all such acts and exercise all such rights and privileges consistent with applicable law and the terms of this Trust Agreement, although not specifically mentioned herein, as Trustee may deem desirable or necessary to control and manage the Trust assets and to carry out the purposes of this Trust Agreement. Except as provided under Section 13.2, if all or any part of the Trust assets are at any time attached, garnished, or levied upon by any court order, or in case the payment, assignment, transfer, conveyance or delivery of any such property shall be stayed or enjoined by any court order, or in case any order, judgment or decree shall be made or entered by a court affecting such property or any part thereof, then and in any of such events Trustee is authorized, in its sole discretion, to rely upon and comply with any such order, writ, judgment or decree, and it shall not be liable to Constellation Energy (or any of its subsidiaries) or any participant by reason of such compliance even though such order, writ, judgment or decree subsequently may be reversed, modified, annulled, set aside or vacated. 8.5 Notwithstanding any powers granted to Trustee pursuant to this Trust Agreement or to applicable law, Trustee shall not have any power that could give this Trust the objective of carrying on a business and dividing the gains therefrom, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Internal Revenue Code. Section 9. Compensation and Expenses of Trustee. 9.1 Constellation Energy shall pay all administrative and Trustee's fees and expenses (including, without limitation, reasonable fees of agents and counsel). If not so paid, the fees and expenses shall be paid from the Trust; provided, however, that Constellation Energy may approve in writing the automatic payment of fees, compensation and expenses from the Trust. Trustee shall have a lien on the Trust in the amount of such fees, expenses and compensation until the same have been paid. 9.2 Constellation Energy shall pay any federal, state, local or other taxes imposed or levied with respect to the Trust assets under the existing or future laws. Section 10. Resignation and Removal of Trustee. 10.1 Trustee may resign at any time by written notice to Constellation Energy, which shall be effective 30 days after receipt of such notice unless Constellation Energy and Trustee agree otherwise in writing. 10.2 Accept as provided in Section 10.3, Trustee may be removed by Constellation Energy on 30 days written notice or upon shorter notice accepted by Trustee. 10.3 Upon a Change of Control, as defined in Section 13.5 hereof, Trustee may not be removed by Constellation Energy for 2 years from the date a Change of Control is deemed to occur under Section 13.5 hereof. 10.4 If Trustee resigns within 2 years of a Change of Control, Trustee shall select a successor Trustee in accordance with the provisions of Section 11.2 hereof prior to the effective date of Trustee's resignation. 10.5 Upon resignation or removal of Trustee and appointment of a successor Trustee, all Trust assets shall subsequently be transferred to the successor Trustee. The transfer shall be completed at the later of (i) 90 days after receipt of notice of resignation or removal of Trustee, or (ii) appointment of successor Trustee, unless Constellation Energy extends the time limit in writing. 10.6 If Trustee resigns or is removed, a successor shall be appointed, in accordance with Section 11 hereof, by the effective date of resignation or removal under Sections 10.1 or 10.2 hereof. If no such appointment has been made, Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of Trustee in connection with the proceeding shall be allowed as administrative expenses of the Trust. Section 11. Appointment of Successor. 11.1 If Trustee resigns or is removed in accordance with Sections 10.1 or 10.2 hereof, Constellation Energy may appoint any third party, such as a bank trust department or other party that may be granted corporate trustee powers under state law, as a successor to replace Trustee upon resignation or removal. The appointment shall be effective when accepted in writing by the successor Trustee, who shall have all of the rights and powers of the former Trustee, including ownership rights in the Trust assets. The former Trustee shall execute any instrument necessary or reasonably requested by Constellation Energy or the successor Trustee (in which case Trustee shall have received a copy of successor Trustee's acceptance) to evidence the transfer of the Trust assets. 11.2 If Trustee resigns pursuant to the provisions of Section 10.4 hereof, Trustee may appoint any third party such as a bank trust department or other party that may be granted corporate trustee powers under state law. The appointment of a successor Trustee shall be effective when accepted in writing by the successor Trustee. The successor Trustee shall have all the rights and powers of the former Trustee, including ownership rights in Trust assets. The former Trustee shall execute any instrument necessary or reasonably requested by the successor Trustee to evidence the transfer of the Trust assets. 11.3 The successor Trustee need not examine the records and acts of any prior Trustee and may retain or dispose of existing Trust assets, subject to Sections 7 and 8 hereof. The successor Trustee shall not be responsible for and Constellation Energy shall indemnify and defend the successor Trustee from any claim or liability resulting from any action or inaction of any prior Trustee or from any other past event, or any condition existing at the time it becomes successor Trustee. 11.4 In the event of such removal or resignation, Trustee shall duly file with Constellation Energy a written account as provided in Section 7.1 hereof. Section 12. Amendment or Termination. 12.1 Except as provided in Section 12.4, this Trust Agreement may be amended by a written instrument executed by Trustee and Constellation Energy. Notwithstanding the foregoing, no such amendment shall conflict with the terms of the Plans or shall make the Trust revocable. 12.2 The Trust shall not terminate until the earlier of the date on which Plan participants and their surviving spouses are no longer entitled to benefits pursuant to the terms of the Plan or have received payment of all benefits to which they are entitled under this Trust Agreement. Upon termination of the Trust any assets remaining in the Trust shall be returned to Constellation Energy. 12.3 Upon written approval of all Plan participants and surviving spouses entitled to payment of benefits pursuant to the terms of the Plans and this Trust Agreement, Constellation Energy may terminate this Trust prior to the time all benefit payments under the Plans and this Trust Agreement have been made. All Trust assets at termination shall be returned to Constellation Energy. 12.4 This Trust Agreement may not be amended by Constellation Energy for 2 years following a Change of Control, unless such amendment is by written agreement between Constellation Energy and Trustee and such amendment does not adversely affect the rights of the Plan participants and their surviving spouses entitled to payment of benefits pursuant to terms of the Plans on the date a Change of Control is deemed to occur. Section 13. Miscellaneous. 13.1 Any provision of this Trust Agreement prohibited by law shall be ineffective to the extent of any such prohibition, without invalidating the remaining provisions hereof. 13.2 Benefits payable to Plan participants and their surviving spouses under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levies, execution or other legal or equitable process, and any attempt to so alienate, sell, transfer, assign, pledge, attach, charge or otherwise encumber any such amount, whether presently or thereafter payable, shall be void. The Trust shall be in no manner liable for or subject to the debts or liabilities of any participant. 13.3 This Trust Agreement shall be governed by and construed in accordance with the laws of the State of New York and Trustee shall be liable to account only in the courts of that state. 13.4 All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Plans. All singular terms defined in this Trust will include the plural and vice versa. ---------- 13.5 For purposes of this Trust Agreement, Change of Control shall mean (a) the purchase or acquisition by any person, entity or group of persons (within the meaning of section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), or any comparable successor provisions) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy or the combined voting power of Constellation Energy's then outstanding shares of voting securities entitled to a vote generally, or (b) the consummation of, following the approval by the stockholders of Constellation Energy of a reorganization, merger, or consolidation of Constellation Energy, in each case, with respect to which persons who were stockholders of Constellation Energy immediately prior to such reorganization, merger, or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity's then outstanding securities, or (c) a liquidation or dissolution of Constellation Energy or the sale of substantially all of its assets, or (d) a change of more than one-half of the members of the Board of Directors of Constellation Energy within a 90-day period for reasons other than death, disability, or retirement of such members. 13.6 Constellation Energy shall certify to Trustee the name or names of any person or persons authorized to act for Constellation Energy under this Trust Agreement. Such certification shall be signed by a Vice President of Constellation Energy. Until Constellation Energy notifies Trustee, in a similarly signed notice or certification, that any such person is no longer authorized to act for Constellation Energy, Trustee may continue to rely upon the authority of such person. Trustee may rely upon any certificate, schedule, notice or direction of Constellation Energy which Trustee in good faith believes to be genuine, executed and delivered by a duly authorized officer or agent of Constellation Energy. Trustee shall have no duty to verify any calculations provided by Constellation Energy in connection with such certificate, schedule, notice or direction. Communications to Trustee shall be sent in writing to Trustee at the address specified in Section 13.9 hereof or to such other address as the Trustee may specify in writing. No communication shall be binding upon the Trust or Trustee until it is received by Trustee and unless it is in writing and signed by an authorized person. Communications to Constellation Energy shall be sent in writing to Constellation Energy's principal offices at the address specified in Section 13.9 hereof or to such other address as Constellation Energy may specify in writing. No communication shall be binding upon Constellation Energy until it is received by Constellation Energy and unless it is in writing and signed by Trustee. 13.7 Constellation Energy shall pay and shall protect, indemnify and save harmless Trustee and its officers, employees and agents from and against any and all losses, liabilities (including liabilities for penalties), actions, suits, judgments, demands, damages, costs and expenses of any nature arising from or relating to any action by or any failure to act by Trustee (and its officers, employees and agents) in accordance with the terms of this Trust Agreement, or the transactions contemplated by this Trust Agreement (including any action by Trustee on the direction or instruction of Constellation Energy or any failure to act on the part of Trustee in the absence of directions or instructions by Constellation Energy), except to the extent that any such loss, liability, action, suit, judgment, demand, damage or expense has been determined by final judgement of a court of competent jurisdiction to be the result of the negligence or willful misconduct of Trustee, its officers, employees or agents. To the extent that Constellation Energy has not fulfilled its obligations under the foregoing provisions of this Section 13.7, Trustee shall be reimbursed out of the Trust assets or may set up reasonable reserves for the payment of such obligations. To the maximum extent permitted by applicable law, no personal liability whatsoever shall attach to or be incurred by any employee, officer or director of Constellation Energy, as such, under or by reason of the terms or conditions contained in or implied from this Trust Agreement. Trustee assumes no obligation or responsibility with respect to any action required by this Trust Agreement on the part of Constellation Energy and shall have those responsibilities only as expressly set forth herein. 13.8 This Trust Agreement sets forth the entire understanding of the parties with respect to the subject matter hereof and supersedes any and all prior agreements, arrangements and understandings relating thereto. 13.9 Any notice, report, demand, waiver or communication required or permitted hereunder shall be in writing and shall be given personally or by prepaid registered or certified mail, return receipt requested, addressed as follows: If to Constellation Energy Group, Inc.: Constellation Investments, Inc. 250 West Pratt Street Baltimore, Maryland 21201 Attention: Steven D. Kesler If to Trustee: Citibank, N. A. Client Services Division 111 Wall Street, 24th Floor New York, NY 10005 Attention: Ed Flannery If to a participant or to a participant's surviving spouse: To the address shown on the most recent Payment Schedule provided by Constellation Energy to Trustee. Section 14. Effective Date. The date of this Trust Agreement shall be July 31, 1994. IN WITNESS WHEREOF, and intending to be legally bound hereby, Constellation Energy Group, Inc. and Trustee sign and seal this Trust Agreement the day and year first above written. WITNESS: CITIBANK, N. A.: ___________________________ By: __________________________(Seal) Name: Sam Borowski Title: Managing Director WITNESS: CONSTELLATION ENERGY GROUP, INC.: ___________________________ By: __________________________(Seal) Name: Janet E. McHugh Title: Vice President Human Resources EX-10.N 4 0004.txt SUPPLEMENTAL PENSION PLAN Exhibit 10(n) CONSTELLATION ENERGY GROUP, INC. -------------------------------- SUPPLEMENTAL PENSION PLAN ------------------------- Effective January 1, 2000 TABLE OF CONTENTS
Page No. 1. Objective 1 2. Definitions 1 3. Plan Administration 4 4. Eligibility 4 5. Supplemental Pension Benefit 5 (a) Generally 5 (b) Retirement benefits 5 (i) Eligibility for retirement benefits 5 (ii) Computation of retirement benefits 5 (iii)Form of payout of retirement benefits 6 (iv) Amount, timing, and source of monthly retirement benefit payout 7 (v) Amount, timing, and source of lump sum retirement benefit payout 7 (vi) Death of participant entitled to lump sum payout 8 (c) Entitlement to benefit upon happening of certain events 8 (i) Computation of gross accrued benefit 8 (ii) Computation of net accrued benefit 9 (iii)Satisfaction of requirements 9 (iv) Other events 10 (1) Change in control 10 (2) Plan amendment 10 (3) Involuntary Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal without Cause 11 (v) Form of benefit payout 11 (vi) Amount, timing and source of benefit payout 11 (vii)Death of participant entitled to lump sum payout 12 6. Supplemental Survivor Annuity Benefit 12 (a) Survivor annuity benefit 12 (i) Eligibility for survivor annuity benefit 12 (ii) Computation of survivor annuity benefit 13 (iii)Form of payout of survivor annuity benefits 15
-2-
(iv) Amount, timing, and source of monthly survivor annuity benefit payout 15 (v) Amount, timing, and source of lump sum survivor benefit payout 15 (vi) Death of surviving spouse entitled to lump sum payout. 16 7. Miscellaneous 16
CONSTELLATION ENERGY GROUP, INC. -------------------------------- SUPPLEMENTAL PENSION PLAN ------------------------- 1. Objective. The objective of this Plan is to enhance the benefits provided --------- to certain officers and key employees of Constellation Energy Group and its subsidiaries in order to attract and retain talented executive personnel. 2. Definitions. All words beginning with an initial capital letter and not ----------- otherwise defined herein shall have the meaning set forth in the Pension Plan. All singular terms defined in this Plan will include the plural and vice versa. As used herein, the following terms will have the meaning ---------- specified below: "Annual Base Salary" means an amount determined by adding the monthly base rate of pay amounts (i.e., the types of such pay that are includable in the computation of Pension Plan benefits)earned over the twelve calendar months immediately preceding the month that includes the date of the computation. "Average Incentive Award" (or "Average Award") means generally the product of the percentage equal to an average of the two highest of the participant's five immediately prior year award percentages earned under Constellation Energy Group's Executive Annual Incentive Plan, Constellation Energy Group's Senior Management Annual Incentive Plan and/or other Incentive Awards Program multiplied by the participant's annualized base rate of pay amount (i.e., the types of such pay that are includable in the computation of Pension Plan benefits) in effect at the end of the prior year. "Benefit Start Date" means the date as of which the participant's benefits, if any, under this Plan commence. "Cause" means the participant's (a) failure to comply with Constellation Energy Group policy, (b) deliberate and continual refusal to satisfactorily perform employment duties on substantially a full-time basis, (c) deliberate and continual refusal to act in accordance with any specific instructions of a majority of Constellation Energy Group's Board of Directors, (d) disclosure, without the consent of a -2- majority of Constellation Energy Group's Board of Directors, of confidential information or trade secrets concerning Constellation Energy Group which could be materially damaging to Constellation Energy Group, or (e) deliberate misconduct which could be materially damaging to Constellation Energy Group without reasonable good faith belief by the participant that such conduct was in the best interest of Constellation Energy Group. "Change in Control" means (a) the purchase or acquisition by any person, entity or group of persons, (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group's then outstanding shares of voting securities entitled to a vote generally, or (b) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger, or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity's then outstanding securities, or (c) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (d) a change of more than one-half of the members of the Board of Directors of Constellation Energy Group within a 90-day period for reasons other than the death, disability, or retirement of such members. "Committee" means the Committee on Management of the Board of Directors of Constellation Energy Group. "Constellation Energy Group" means Constellation Energy Group, Inc., a Maryland corporation, or its successor. "Constellation Energy Group's Executive Annual Incentive Plan" means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator. -3- "Constellation Energy Group's Senior Management Annual Incentive Plan" means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator. "Demotion" means a transfer to a position with Constellation Energy Group or a subsidiary of Constellation Energy Group that either (a) is substantially below the position in which the participant was employed on the date of transfer, or (b) results in a substantial reduction in pay when compared to the participant's pay on the date of the transfer. Whether a position is a substantially below another position shall be determined in the reasonable discretion of the Committee, with reference to factors including whether the participant retains principal responsibility for a department or division, and whether the participant remains eligible for the perquisites enjoyed by the participant before the position change. "Early Receipt Reduction Factor" means 100% less .25% for each month that the participant is less than age 62 on the participant's Benefit Start Date. "Interest Rate" means the rate equal to the average monthly 30-year Treasury bond rate for the second calendar quarter preceding the computation date, less 50 basis points. "Internal Revenue Code Limitations" means the limitations under Sections 415 and/or 401(a)(17) of the Internal Revenue Code. "LTD Plan" means the Constellation Energy Group, Inc. Disability Insurance Plan as may be amended from time to time, or any successor plan. "Mortality Table" means the mortality table used to convert annuities to lump sums in the Pension Plan. "Other Incentive Awards Program" means the program(s) designated in writing by the Plan Administrator applicable to certain employees that provides awards; but includes only the types of awards that are includable in the computation of Pension Plan benefits. "Pension Plan" means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan. -4- "Plan" means this Constellation Energy Group, Inc. Supplemental Pension Plan. "Plan Administrator" means, as set forth in Section 3, the Committee. "Rabbi Trust" means the trust adopted by Constellation Energy Group pursuant to the Grantor Trust Agreement Dated as of January 1, 2001, between Constellation Energy Group and Citibank, N.A. "Survivor Annuity Percentage" means 50%, unless the participant elects in the timing and manner established by the Plan Administrator, a higher percentage (in multiples of 5% to a total percentage not to exceed 100%). "Termination From Employment With Constellation Energy Group" means a participant's separation from service with Constellation Energy Group or a subsidiary of Constellation Energy Group; however, a participant's retirement, disability, or transfer of employment to or from a subsidiary of Constellation Energy Group shall not constitute a Termination From Employment With Constellation Energy Group. 3. Plan Administration. The Committee is the Plan Administrator and has sole ------------------- authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. Appeals of written decisions by the Plan Administrator may be made to the Board of Directors of Constellation Energy Group. Decisions by the Board shall be final and not subject to further appeal. The Plan Administrator shall have the power to delegate all or any part of its duties to one or more designees, and to withdraw such authority, by written designation. 4. Eligibility. The officers or key employees of Constellation Energy Group ----------- or its subsidiaries designated in Appendix A are participants under the Plan. Participation shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator, provided, however, that such withdrawal may not be made for benefits provided pursuant to Sections 5 and 6 with respect to a participant who has satisfied the eligibility requirements to retire (as set forth in Section 5(b)(i)). Notwithstanding the foregoing, any participant while -5- classified as disabled under the LTD Plan shall continue to participate in this Plan while classified as disabled and, for purposes of the supplemental pension benefit provided by this Plan, while classified as disabled, shall be deemed to continue to accrue Credited Service until no later than his/her Normal Retirement Date. 5. Supplemental Pension Benefit. ----------------------------- (a) Generally. A participant shall be eligible for supplemental pension --------- benefits and supplemental survivor annuity benefits under this Plan only if the participant's supplemental pension benefits under this Plan are greater than the supplemental pension benefits computed under the Executive Benefits Plan based on the participant's age, service, and eligible compensation on the date as of which benefits become payable. (b) Retirement benefits. ------------------- (i) Eligibility for retirement benefits. A participant shall be ----------------------------------- eligible to retire under this Plan on or after the participant's Normal Retirement Date, or on the first day of any month preceding his/her Normal Retirement Date, if on his/her Severance From Service Date and while a participant he/she has attained (1) age 55 and has accumulated at least 10 years of Credited Service; or (2) age 60 and has accumulated at least one year of Credited Service. (ii) Computation of retirement benefits. A participant who is ---------------------------------- eligible to retire under this Plan will be entitled to supplemental pension retirement benefits under this Plan, which will be calculated as set forth below on the participant's Benefit Start Date: (1) add the Annual Base Salary and the Average Incentive Award, (2) divide the sum by 12, (3) multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board of Constellation Energy Group - 60%; all other -6- participants (by completed years of Credited Service) 1 through 9 - 3% per year; 10 through 19 - 40%; 20 through 24 -45%; 25 through 29 - 50%; and 30 or more - 55%, (4) multiply this dollar amount by the Early Receipt Reduction Factor; provided, however, if the participant is age 62 or older, such factor shall be one (1), (5) subtract from this dollar amount the charges relating to coverage for a preretirement survivor annuity in excess of 50%, and for a post-retirement survivor annuity in excess of 50%, and (6) subtract from the remainder the net amount payable to the participant under the Pension Plan on the participant's Benefit Start Date, assuming a 50% spousal joint and survivor annuity for a married participant(if the participant is not eligible to commence monthly Pension Plan payments on the participant's Benefit Start Date, the participant's benefit will be unreduced for Pension Plan payments until the date the participant is first eligible to commence monthly Pension Plan payments), or, if the participant elects a lump sum under the PEP provisions of the Pension Plan, the monthly amount that would have been payable under the Pension Plan as a life annuity for a single participant or as a 50% spousal joint and survivor annuity for a married participant, as of the Benefit Start Date under this Plan. (iii) Form of payout of retirement benefits. Each participant entitled ------------------------------------- to supplemental pension retirement benefits will receive his/her supplemental pension retirement benefits payout in the form of a monthly payment, unless the participant makes a valid election to receive his/her supplemental pension retirement benefits payout in the form of a lump sum. A participant may elect to receive his/her supplemental pension retirement benefits payout in the form of a lump sum by submitting to the Plan -7- Administrator a signed Lump Sum Election Form. The Form must be received by the Plan Administrator before the beginning of the calendar year during which the participant's Severance From Service Date occurs. The election may be revoked at any time before the beginning of the calendar year during which the participant's Severance From Service Date occurs, by submitting to the Plan Administrator a signed Lump Sum Revocation Form. (iv) Amount, timing, and source of monthly retirement benefit payout. --------------------------------------------------------------- A participant entitled to monthly supplemental pension retirement benefits will receive monthly payments equal to the amount determined under paragraph (b)(ii). Such payments shall commence effective with the first of the month following the participant's Severance From Service Date. If such participant receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s). Monthly payments hereunder shall permanently cease upon the death of the participant, effective with the monthly payment for the month following the month of the participant's death. Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. (v) Amount, timing, and source of lump sum retirement benefit payout. ---------------------------------------------------------------- A participant entitled to a lump sum supplemental pension retirement benefit will receive a lump sum payment. This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity including the estimated present value of post-retirement supplemental survivor annuity benefits described in Section 6, and reflecting the present value of any deferred Pension Plan payments using (1) the supplemental pension retirement benefit amount calculated under paragraph (b)(ii), which is expressed as a monthly amount, (2) the Interest Rate computed on the -8- participant's Benefit Start Date, and (3) the Mortality Table. Such lump sum payment shall be made within 60 days after the participant's Retirement Date. The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A participant who receives a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan. (vi) Death of participant entitled to lump sum payout. In the event ------------------------------------------------ of the death of a participant after his/her Severance From Service Date and before the participant receives the lump sum payment under paragraph (b)(v), such lump sum payment shall be made to the participant's surviving spouse (as defined in Section 6(i)). The lump sum payment shall be the same amount and made at the same time and from the same sources as set forth in paragraph (b)(v). If there is no surviving spouse at the date of the participant's death, no payments shall be made pursuant to Sections 5 or 6. A surviving spouse who receives a lump sum benefit under this paragraph (b)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to post- retirement survivor annuity coverage under the Plan. (c) Entitlement to benefit upon happening of certain events. ------------------------------------------------------- (i) Computation of gross accrued benefit. The computation of the ------------------------------------ gross accrued supplemental pension benefit for a participant as of the date of the computation will be made as follows: (1) add the Annual Base Salary and the Average Incentive Award, (2) divide the sum by 12, and (3) multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board of -9- Constellation Energy Group - 60%; all other participants (by completed years of Credited Service as of the date of the computation) 1 through 9 - 3% per year; 10 through 19 - 40%; 20 through 24 - 45%; 25 through 29 - 50%; and 30 or more - 55%. (ii) Computation of net accrued benefit. The computation of the net ---------------------------------- accrued supplemental pension benefit for a participant as of the date of the computation will be made by subtracting from the gross accrued benefit determined under paragraph (c)(i) the amount of the participant's Gross Pension under the Pension Plan determined as of the date of the computation and assuming that monthly payments of such Gross Pension begin on the first of the month after the later of reaching age 62 or the date of the computation. If the participant is not eligible for payment of a Gross Pension under the Pension Plan, the participant's Accrued Gross Pension determined as of the date of the computation shall be substituted for the Gross Pension described above, with the appropriate reduction for early receipt applied as if the participant were eligible to begin payment of his Accrued Gross Pension on the first of the month after the later of reaching age 62 or the date of the computation. (iii) Satisfaction of requirements. A participant who has satisfied ---------------------------- the age and Credited Service requirements set forth in Section 5(b)(i) while eligible as set forth in Section 4, but who the Committee determines does not retire under the Plan due to Demotion, Termination From Employment With Constellation Energy Group, or the withdrawal of a participant's eligibility to participate under Section 5, shall be entitled to his/her net accrued supplemental pension benefit. The effective date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal event shall be the date of such Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal. (iv) Other events. A participant, regardless of his/her age and years ------------ of Credited Service, shall -10- be entitled to his/her net accrued supplemental pension benefit upon the happening of any of the following entitlement events, but only if such entitlement event occurs while a participant and before a participant retires under this Plan: (1) Change in Control. A Change in Control, followed within two ----------------- years by the participant's Demotion, a participant's Termination From Employment With Constellation Energy Group, or the withdrawal of the participant's eligibility to participate under the Plan, is an entitlement event. The effective date of the entitlement event shall be the date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal. (2) Plan amendment. A Plan amendment that has the effect of -------------- reducing a participant's gross accrued supplemental pension benefit is an entitlement event. In determining whether such a reduction has occurred, the participant's gross accrued supplemental pension benefit calculated on the day immediately preceding the effective date of the amendment shall be compared to the participant's gross accrued supplemental pension benefit calculated on the effective date of the amendment. An amendment that has the effect of reducing future benefit accruals is not an entitlement event. It is intended that an entitlement event under this paragraph (c)(iv)(2) will occur only with respect to those amendments that are substantially similar to amendments that are prohibited by Internal Revenue Code section 411(d)(6) with respect to qualified pension plans. The effective date of the entitlement event shall be the effective date of the Plan amendment. -11- (3) Involuntary Demotion, Termination From Employment With ------------------------------------------------------ Constellation Energy Group, or eligibility withdrawal ----------------------------------------------------- without Cause. A participant's involuntary Demotion or ------------- involuntary Termination From Employment With Constellation Energy Group without Cause, or the withdrawal of a participant's eligibility to participate under Sections 5 or 6 of the Plan without Cause, is an entitlement event. The effective date of the entitlement event shall be the effective date of the participant's involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the eligibility withdrawal without Cause. (v) Form of benefit payout. Each participant entitled to a payout ---------------------- under this paragraph (c) will receive such payout in the form of a lump sum payment. (vi) Amount, timing, and source of benefit payout. A participant -------------------------------------------- entitled to a payout of his/her net accrued benefit, as a result of the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) will be entitled to a lump sum benefit. This lump sum benefit will be calculated by a certified actuary as the present value, determined as of the date of payment, of an annuity beginning at age 62 (or the participant's actual age, if the participant is older than age 62 on the date the lump sum benefit is payable), including the estimated present value of post-retirement survivor annuity benefits described in Section 7, using (1) the net accrued benefit amount calculated under paragraph (d)(ii) on the effective date of the entitlement event, which is expressed as a monthly amount, (2) the Interest Rate computed on the date the lump sum benefit is payable, and (3) the Mortality Table. The lump sum benefit shall be payable as of the participant's Severance From service Date, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A participant who receives a lump sum benefit under this paragraph (c)(vi) shall not be entitled to -12- any cost of living or other pension payment adjustments or to preretirement or post-retirement survivor annuity coverage. (vii) Death of participant entitled to lump sum payout. In the event ------------------------------------------------ of the death of a participant after the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) and before the participant receives the lump sum payment under paragraph (c)(v), such lump sum payment shall be made to the participant's surviving spouse (as defined in Section 6(i)). The lump sum payment will be calculated by a certified actuary and will be equal to 100% of the lump sum that would have been paid to the participant under paragraph (vi), as of the date on which the lump sum is payable under this paragraph (vii), provided that the participant's date of death is on or after his/her Severance From Service Date. If the participant's date of death is before his/her Severance From Service Date, 50% shall be substituted for 100% in the preceding sentence. The lump sum benefit shall be payable as of the earlier of the participant's Severance From Service Date or date of death, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. If there is no surviving spouse at the date of the participant's death, no payments shall be made pursuant to Sections 5 or 6. A surviving spouse who receives a lump sum benefit under this paragraph (c) (vii) shall not be entitled to any cost of living or other pension payment adjustments or to preretirement or post-retirement survivor annuity coverage under the Plan. 6. Supplemental Survivor Annuity Benefit. ------------------------------------- (a) Survivor annuity benefit. ------------------------ (i) Eligibility for survivor annuity benefit. Following the death of ---------------------------------------- a participant who is fully vested under the Pension Plan, a supplemental survivor annuity may be paid to the participant's surviving spouse until the death of that spouse, using the Survivor Annuity Percentage. The -13- participant will not bear the cost of up to a 50% survivor annuity benefit, but will bear the cost of a survivor annuity benefit in excess of 50%. For purposes of this Section 6(a), a participant's surviving spouse is the individual married to the participant on the date of the participant's death. If there is no surviving spouse, or if the participant or the participant's spouse previously received or is entitled to receive either a lump sum payment under Section 5, or a benefit under the Senior Executive Supplemental Plan, no supplemental survivor annuity will be payable. (ii) Computation of survivor annuity benefit. The amount of the --------------------------------------- supplemental survivor annuity will be determined as follows: (1) if the participant's Benefit Start Date occurred prior to the date of death: (a) begin with the monthly pension benefit (under Section 5(b) of this Plan) that the participant was receiving prior to the date of death, and (b) multiply this dollar amount by the Survivor Annuity Percentage. (2) otherwise: (a) Unless the participant elected the alternative in- service death benefit in section (b) below: (1) begin with the monthly Early Retirement pension benefit (under both the Pension Plan and Section 5(b) of this Plan) to which the participant would have been entitled to receive if: the participant had been retired at the later of age 60 or his/her actual age on the date of death for purposes of computing the Early Receipt Reduction Factor, (2) multiply this dollar amount by the Survivor Annuity Percentage , -14- (3) subtract from the product the net amount, if any, of the survivor annuity provided on behalf of the participant under the Pension Plan if the participant is participating in the Traditional Pension Plan, or the monthly annuity that would have been provided to the participant's spouse assuming that he or she had been designated as the participant's beneficiary and had chosen to receive a survivor benefit in the form of a monthly annuity, if the participant is participating in the PEP, and (4) subtract from this dollar amount the charges relating to coverage (under both the Pension Plan and this Plan) for a preretirement survivor annuity in excess of 50%. (b) If the participant was a participant in the Pension Equity Plan option of the Pension Plan and elected this alternative in-service death benefit by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator (1) calculate the benefit under the Constellation Energy Group Benefits Restoration Plan that would have been payable to the surviving spouse if the participant were a participant in that plan and (2) that dollar amount will be paid to the surviving spouse only in the form of a lump sum from this Plan. (iii) Form of payout of survivor annuity benefits. Unless the ------------------------------------------- participant made a valid election by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator, to have the survivor benefits paid in a lump sum, each -15- surviving spouse entitled to a supplemental survivor annuity benefit will receive his/her survivor annuity benefit payout in the form of a monthly payment. (iv) Amount, timing, and source of monthly survivor annuity benefit -------------------------------------------------------------- payout. A surviving spouse entitled to monthly supplemental ------ survivor annuity benefits will receive a monthly payment equal to the amount determined under (ii) above. Such payments shall commence effective with the first day of the month following the month of the participant's death. If such surviving spouse receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s). Monthly payments hereunder shall permanently cease upon the death of the surviving spouse, effective with the monthly payment for the month following the month of the surviving spouse's death. Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. (v) Amount, timing, and source of lump sum survivor benefit payout. A -------------------------------------------------------------- surviving spouse entitled to a lump sum supplemental survivor benefit will receive a lump sum payment. This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity. Such lump sum payment shall be made within 60 days after the participant's death. The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A surviving spouse who receives a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments. (vi) Death of surviving spouse entitled to lump sum payout. In the ----------------------------------------------------- event of the death of a surviving spouse before the spouse receives the lump sum -16- payment under section 6(a)(v) no payment shall be made. 7. Miscellaneous. None of the benefits provided under this Plan shall be ------------- subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; or (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability. This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall reduce any previously accrued supplemental pension benefit under this Plan or impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action. All amendments to this Plan which would increase or decrease the compensation of any Officer of Constellation Energy Group, either directly or indirectly, must be approved by the Board of Directors. All other permissible amendments may be made at the written direction of the Committee. Notwithstanding anything else in this Plan to the contrary, the Constellation Energy Group Board of Directors may authorize a Participant to be eligible for benefits or may increase benefit payments. Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person. The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974. Constellation Energy Group shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust. Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of Constellation Energy Group and no person other than Constellation Energy Group shall by virtue of the provisions of this Plan have any interest in such funds and assets. To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group. -17- In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the "New Company"), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan. This Plan shall be governed in all respects by Maryland law. EX-10.O 5 0005.txt SENIOR EXECUTIVE SUPP. PLAN Exhibit 10(o) CONSTELLATION ENERGY GROUP, INC. -------------------------------- SENIOR EXECUTIVE SUPPLEMENTAL PLAN ---------------------------------- Effective January 1, 2000 CONSTELLATION ENERGY GROUP, INC. -------------------------------- SENIOR EXECUTIVE SUPPLEMENTAL PLAN ---------------------------------- 1. Objective. The objective of this Plan is to enhance the benefits provided --------- to certain senior executives of Constellation Energy Group and its subsidiaries in order to attract and retain talented executive personnel. 2. Definitions. All words beginning with an initial capital letter and not ----------- otherwise defined herein shall have the meaning set forth in the Pension Plan. All singular terms defined in this Plan will include the plural and vice versa. As used herein, the following terms will have the meaning ---------- specified below: "Average Annual Base Salary" means an amount determined by (a) computing the monthly base rate of pay amounts (i.e., the types of such pay that are includable in the computation of Pension Plan benefits) paid during the prior five consecutive twelve month periods immediately preceding the month that includes the date of the computation, and (b) averaging the two twelve month periods during which the highest amounts were paid. "Average Incentive Award" (or "Average Award") means the average of the two highest of the participant's five immediately prior year awards earned under Constellation Energy Group's Executive Annual Incentive Plan, Constellation Energy Group's Senior Management Annual Incentive Plan and/or Other Incentive Awards Programs. "Benefit Start Date" means the date as of which the participant's benefits, if any, under this Plan commence. "Cause" means the participant's (a) failure to comply with Constellation Energy Group policy, (b) deliberate and continual refusal to satisfactorily perform employment duties on substantially a full-time basis, (c) deliberate and continual refusal to act in accordance with any specific instructions of a majority of Constellation Energy Group's Board of Directors, (d) disclosure, without the consent of a majority of Constellation Energy Group's Board of Directors, of confidential information or trade secrets concerning Constellation Energy Group which could be materially damaging to Constellation Energy Group, or (e) deliberate misconduct which could be materially damaging to Constellation Energy Group without reasonable good faith belief by the participant that such conduct was in the best interest of Constellation Energy Group. "Change in Control" means (a) the purchase or acquisition by any person, entity or group of persons, (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group's then outstanding shares of voting securities entitled to a vote generally, or (b) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger, or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity's then outstanding securities, or (c) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (d) a change of more than one-half of the members of the Board of Directors of Constellation Energy Group within a 90-day period for reasons other than the death, disability, or retirement of such members. "Committee" means the Committee on Management of the Board of Directors of Constellation Energy Group. "Constellation Energy Group" means Constellation Energy Group, Inc., a Maryland corporation, or its successor. "Constellation Energy Group's Executive Annual Incentive Plan" means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator. "Constellation Energy Group's Senior Management Annual Incentive Plan" means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator. "Demotion" means a transfer to a position with Constellation Energy Group or a subsidiary of Constellation Energy Group that either (a) is substantially below the position in which the participant was employed on the date of transfer, or (b) results in a substantial reduction in pay when compared to the participant's pay on the date of the transfer. Whether a position is substantially below another position shall be determined in the reasonable discretion of the Committee, with reference to factors including whether the participant retains principal responsibility for a department or division, and whether the participant remains eligible for the perquisites enjoyed by the participant before the position change. "Early Receipt Reduction Factor" means 100% less 1/3 of 1% for each month that the participant is less than age 62 on the participant's Benefit Start Date. "Interest Rate" means the rate equal to the average monthly 30-year Treasury bond rate for the second calendar quarter preceding the computation date, less 50 basis points. "Internal Revenue Code Limitations" means the limitations under Section 415 and/or 401(a)(17) of the Internal Revenue Code. "LTD Plan" means the Constellation Energy Group, Inc. Disability Insurance Plan as may be amended from time to time, or any successor plan. "Mortality Table" means the mortality table used to convert annuities to lump sums in the Pension Plan. "Other Incentive Awards Program" means the program(s) designated in writing by the Plan Administrator applicable to certain employees that provides awards; but includes only the types of awards that are includable in the computation of Pension Plan benefits. "Pension Plan" means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan. "Plan" means this Constellation Energy Group, Inc. Senior Executive Supplemental Plan. "Plan Administrator" means, as set forth in Section 3, the Committee. "Rabbi Trust" means the trust adopted by Constellation Energy Group pursuant to the Grantor Trust Agreement Dated as of January 1, 2001, between Constellation Energy Group and Citibank, N.A. "Survivor Annuity Percentage" means 50%, unless the participant elects, in the timing and manner established by the Plan Administrator, a higher percentage (in multiples of 5% to a total percentage not to exceed 100%). "Termination From Employment With Constellation Energy Group" means a participant's separation from service with Constellation Energy Group or a subsidiary of Constellation Energy Group; however, a participant's retirement, disability, or transfer of employment to or from a subsidiary of Constellation Energy Group shall not constitute a Termination From Employment With Constellation Energy Group. "Total SERP Service" means (a) Credited Service accumulated while designated as a participant with respect to supplemental pension benefits under this Plan or while a participant under the Constellation Energy Group Supplemental Pension Plan, or while a participant under any predecessor executive supplemental pension benefit plan, plus (b) one fourth of Credited Service accumulated while not such a participant. 3. Plan Administration. The Committee is the Plan Administrator and has sole ------------------- authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. Appeals of written decisions by the Plan Administrator may be made to the Board of Directors of Constellation Energy Group. Decisions by the Board shall be final and not subject to further appeal. The Plan Administrator shall have the power to delegate all or any part of its duties to one or more designees, and to withdraw such authority, by written designation. 4. Eligibility. Each senior executive of Constellation Energy Group or its ----------- subsidiaries may be designated in writing by the Plan Administrator as a participant with respect to one or more benefits under the Plan. Once designated, participation shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator, provided, however, that such withdrawal may not be made with respect to a participant who has satisfied the eligibility requirements to retire (as set forth in Section 5(b)(i)). Notwithstanding the foregoing, any participant while classified as disabled under the LTD Plan shall continue to participate in this Plan while classified as disabled and, for purposes of the supplemental pension benefit provided by this Plan, while classified as disabled, shall be deemed to continue to accrue Credited Service until no later than his/her Normal Retirement Date. 5. Supplemental Pension Benefit. ----------------------------- (a) Generally. --------- (i) A Plan participant who was a participant in the Constellation Energy Group Supplemental Pension Plan on January 1, 2000, shall be eligible for supplemental pension benefits under this Plan only if the participant's supplemental pension benefits under this Plan are greater than the supplemental pension benefits computed under the Constellation Energy Group Supplemental Pension Plan based on the participant's age, service, and eligible compensation on the date as of which benefits become payable. If a participant or a participant's surviving spouse receives benefits from this Plan, he/she cannot also receive benefits from the Constellation Energy Group Supplemental Pension Plan. (ii) Any other participant in the Plan shall be eligible for benefits under this Plan without regard to any computation under the Constellation Energy Group Supplemental Pension Plan. (b) Retirement benefits. ------------------- (i) Eligibility for retirement benefits. A participant shall be ----------------------------------- eligible to retire under this Plan on or after the participant's Normal Retirement Date, or on the first day of any month preceding his/her Normal Retirement Date, if on his/her Severance From Service Date and while a participant he/she has attained (1) age 55 and has accumulated at least 10 years of Credited Service; or (2) age 62 and has accumulated at least five years of Credited Service. (ii) Computation of retirement benefits. A participant who is ---------------------------------- eligible to retire under this Plan will be entitled to supplemental pension retirement benefits under this Plan, which will be calculated as set forth below on the participant's Benefit Start Date: (1) add the Average Annual Base Salary and the Average Incentive Award, (2) divide the sum by 12, (3) multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board of Constellation Energy Group - 60%; all other participants (the product of 5.5% multiplied by the number of full and fractional years of Total SERP Service), (maximum is 55%). (4) multiply this dollar amount by the Early Receipt Reduction Factor; provided, however, if the participant is age 62 or older on his/her Benefit Start Date, such factor shall be one (1), (5) subtract from this dollar amount the charges relating to coverage for a pre-retirement survivor annuity in excess of 50%, and for a post-retirement survivor annuity in excess of 50%, and (6) subtract from the remainder the net monthly amount payable to the participant under the Pension Plan on the participant's Benefit Start Date (assuming a 50% spousal joint and survivor annuity for a married participant), (if the participant is not eligible to commence monthly Pension Plan payments on the participant's Benefit Start Date, the participant's benefit will be unreduced for Pension Plan payments until the date the participant is first eligible to commence monthly Pension Plan payments) , or, if the participant elects a lump sum under the PEP provisions of the Pension Plan, the monthly amount that would have been payable under the Pension Plan as a life annuity for a single participant or as a 50% spousal joint and survivor annuity for a married participant, as of the Benefit Start Date under this Plan. (iii) Form of payout of retirement benefits. Each participant entitled ------------------------------------- to supplemental pension retirement benefits will receive his/her supplemental pension retirement benefits payout in the form of a monthly payment, unless the participant makes a valid election to receive his/her supplemental pension retirement benefits payout in the form of a lump sum. A participant may elect to receive his/her supplemental pension retirement benefits payout in the form of a lump sum by submitting to the Plan Administrator a signed Lump Sum Election Form. The Form must be received by the Plan Administrator before the beginning of the calendar year during which the participant's Severance From Service Date occurs. The election may be revoked at any time before the beginning of the calendar year during which the participant's Severance From Service Date occurs, by submitting to the Plan Administrator a signed Lump Sum Revocation Form. (iv) Amount, timing, and source of monthly retirement benefit payout. --------------------------------------------------------------- A participant entitled to monthly supplemental pension retirement benefits will receive monthly payments equal to the amount determined under paragraph (b)(ii). Such payments shall commence effective with the first of the month following the Participant's Severance From Service Date. If such participant receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s). Monthly payments hereunder shall permanently cease upon the death of the participant, effective with the monthly payment for the month following the month of the participant's death. Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. (v) Amount, timing, and source of lump sum retirement benefit payout. ---------------------------------------------------------------- A participant entitled to a lump sum supplemental pension retirement benefit will receive a lump sum payment. This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity including the estimated present value of post-retirement supplemental survivor annuity benefits described in Section 6, and reflecting the present value of any deferred Pension Plan payments using (1) the supplemental pension retirement benefit amount calculated under paragraph (b)(ii), which is expressed as a monthly amount, (2) the Interest Rate computed on the participant's Benefit Start Date, and (3) the Mortality Table. Such lump sum payment shall be made within 60 days after the participant's Severance From Service Date. The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A participant who receives a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan. (vi) Death of participant entitled to lump sum payout. In the event ------------------------------------------------ of the death of a participant after his/her Severance From Service Date and before the participant receives the lump sum payment under paragraph (b)(v), such lump sum payment shall be made to the participant's surviving spouse (as defined in Section 6(i)). The lump sum payment shall be the same amount and made at the same time and from the same sources as set forth in paragraph (b)(v). If there is no surviving spouse at the date of the participant's death, no payments shall be made pursuant to Sections 5 or 6. A surviving spouse who receives a lump sum benefit under this paragraph (b)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to post- retirement survivor annuity coverage under the Plan. (c) Entitlement to benefit upon happening of certain events. ------------------------------------------------------- (i) Computation of gross accrued benefit. The computation of the ------------------------------------ gross accrued supplemental pension benefit for a participant as of the date of the computation will be made as follows: (1) add the Average Annual Base Salary and the Average Incentive Award, (2) divide the sum by 12, and (3) multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board and President of Constellation Energy Group - 60%; all other participants (by the product of 5.5% multiplied by the number of full and fractional years of Total SERP Service as of the date of the computation) (maximum is 55%). (ii) Computation of net accrued benefit. The computation of the net ---------------------------------- accrued supplemental pension benefit for a participant as of the date of the computation will be made by subtracting from the gross accrued benefit determined under paragraph (c)(i) the amount of the participant's Gross Pension under the Pension Plan determined as of the date of the computation and assuming that monthly payments of such Gross Pension begin on the first of the month after the later of reaching age 62 or the date of the computation. If the participant is not eligible for payment of a Gross Pension under the Pension Plan, the participant's Accrued Gross Pension determined as of the date of the computation shall be substituted for the Gross Pension described above, with the appropriate reduction for early receipt applied as if the participant were eligible to begin payment of his Accrued Gross Pension on the first of the month after the later of reaching age 62 or the date of the computation. (iii) Satisfaction of requirements. A participant who has satisfied ---------------------------- the age and Credited Service requirements set forth in Section 5(b)(i) while eligible as set forth in Section 4, but who does not retire under the Plan due to Demotion, Termination From Employment With Constellation Energy Group, or the withdrawal of a participant's eligibility to participate under Section 5, shall be entitled to his/her net accrued supplemental pension benefit. The effective date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal event shall be the date of such Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal. (iv) Other events. A participant, regardless of his/her age and years ------------ of Credited Service, shall be entitled to his/her net accrued supplemental pension benefit upon the happening of any of the following entitlement events, but only if such entitlement event occurs while a participant and before a participant retires under this Plan: (1) Change in Control. A Change in Control, followed within two ----------------- years by the participant's Demotion, a participant's Termination From Employment With Constellation Energy Group, or the withdrawal of the participant's eligibility to participate under the Plan, is an entitlement event. The effective date of the entitlement event shall be the date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal. (2) Plan amendment. A Plan amendment that has the effect of -------------- reducing a participant's gross accrued supplemental pension benefit is an entitlement event. In determining whether such a reduction has occurred, the participant's gross accrued supplemental pension benefit calculated on the day immediately preceding the effective date of the amendment shall be compared to the participant's gross accrued supplemental pension benefit calculated on the effective date of the amendment. An amendment that has the effect of reducing future benefit accruals is not an entitlement event. It is intended that an entitlement event under this paragraph (c)(iii)(2) will occur only with respect to those amendments that are substantially similar to amendments that are prohibited by Internal Revenue Code section 411(d)(6) with respect to qualified pension plans. The effective date of the entitlement event shall be the effective date of the Plan amendment. (3) Involuntary Demotion, Termination From Employment With ------------------------------------------------------ Constellation Energy Group, or eligibility withdrawal ----------------------------------------------------- without Cause. A participant's involuntary Demotion or ------------- involuntary Termination From Employment With Constellation Energy Group without Cause, or the withdrawal of a participant's eligibility to participate under Sections 5 or 6 of the Plan without Cause, is an entitlement event. The effective date of the entitlement event shall be the effective date of the participant's involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the eligibility withdrawal without Cause. (v) Form of benefit payout. Each participant entitled to a payout ---------------------- under this paragraph (c) will receive such payout in the form of a lump sum payment. (vi) Amount, timing, and source of benefit payout. A participant -------------------------------------------- entitled to a payout of his/her net accrued benefit, as a result of the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) will be entitled to a lump sum benefit. This lump sum benefit will be calculated by a certified actuary as the present value, determined as of the date of payment, of an annuity beginning at age 62 (or the participant's actual age, if the participant is older than age 62 on the date the lump sum benefit is payable), including the estimated present value of post-retirement survivor annuity benefits described in Section 6, using (1) the net accrued benefit amount calculated under paragraph (d)(iv) on the effective date of the entitlement event, which is expressed as a monthly amount, (2) the Interest Rate computed on the date the lump sum benefit is payable, and (3) the Mortality Table. The lump sum benefit shall be payable as of of the participant's Severance From Service Date, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A participant who receives a lump sum benefit under this paragraph (c)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to pre-retirement or post-retirement survivor annuity coverage. (vii) Death of participant entitled to lump sum payout. In the event ------------------------------------------------ of the death of a participant after the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) and before the participant receives the lump sum payment under paragraph (c)(vi), a lump sum payment shall be made to the participant's surviving spouse (as defined in Section 6(i)). The lump sum payment will be calculated by a certified actuary and will be equal to 100% of the lump sum that would have been paid to the participant under paragraph (vi), as of the date on which the lump sum is payable under this paragraph (vii), provided that the participant's date of death is on or after his/her Severance From Service Date. If the participant's date of death is before his/her Severance From Service Date, 50% shall be substituted for 100% in the preceding sentence. The lump sum benefit shall be payable as of the earlier of the participant's Severance From Service Date or date of death, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. If there is no surviving spouse at the date of the participant's death, no payments shall be made pursuant to Sections 5 or 6. A surviving spouse who receives a lump sum benefit under this paragraph (c) (vii) shall not be entitled to any cost of living or other pension payment adjustments or to pre-retirement or post-retirement survivor annuity coverage under the Plan. 6. Supplemental Survivor Annuity Benefit. ------------------------------------- (a) Survivor annuity benefit. ------------------------ (i) Eligibility for survivor annuity benefit. Following the death of ---------------------------------------- a participant who is fully vested under the Pension Plan, a supplemental survivor annuity may be paid to the participant's surviving spouse until the death of that spouse, using the Survivor Annuity Percentage. The participant will not bear the cost of up to a 50% survivor annuity benefit, but will bear the cost of a survivor annuity benefit in excess of 50%. For purposes of this Section 6(a), a participant's surviving spouse is the individual married to the participant on the date of the participant's death. If there is no surviving spouse, or if the participant or the participant's spouse previously received or is entitled to receive a lump sum payment under Section 5, no supplemental survivor annuity will be payable. (ii) Computation of survivor annuity benefit. The amount of the --------------------------------------- supplemental survivor annuity will be determined as follows: (1) if the participant's Benefit Start Date occurred prior to the date of death: (a) begin with the monthly pension benefit (under Section 5(b) of this Plan) that the participant was receiving prior to the date of death, and (b) multiply this dollar amount by the Survivor Annuity Percentage. (2) otherwise: (a) Unless the participant elected the alternative in- service death benefit in section (b) below: (1) begin with the monthly Early Retirement pension benefit (under both the Pension Plan and Section 5(b) of this Plan) to which the participant would have been entitled if the participant had been retired at the later of age 60 or his/her actual age on the date of death for purposes of computing the Early Receipt Reduction Factor, (2) multiply this dollar amount by the Survivor Annuity Percentage, (3) subtract from the product the net amount, if any, of the survivor annuity provided on behalf of the participant under the Pension Plan if the participant is participating in the Traditional Pension Plan, or the monthly annuity that would have been provided to the participant's spouse assuming that he or she had been designated as the participant's beneficiary and had chosen to receive a survivor benefit in the form of a monthly annuity, if the participant is participating in the PEP, and (4) subtract from this dollar amount the charges relating to coverage (under both the Pension Plan and this Plan) for a pre-retirement survivor annuity in excess of 50%. (b) If the participant was a participant in the Pension Equity Plan option of the Pension Plan and elected this alternative in-service death benefit by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator (1) calculate the benefit under the Constellation Energy Group Benefits Restoration Plan that would have been payable to the surviving spouse if the participant were a participant in that plan and (2) that dollar amount will be paid to the surviving spouse only in the form of a lump sum from this Plan. (iii) Form of payout of survivor annuity benefits. Unless the ------------------------------------------- participant made a valid election by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator, to have the survivor benefits paid in a lump sum, each surviving spouse entitled to a supplemental survivor annuity benefit will receive his/her survivor annuity benefit payout in the form of a monthly payment. (iv) Amount, timing, and source of monthly survivor annuity benefit -------------------------------------------------------------- payout. A surviving spouse entitled to monthly supplemental ------ survivor annuity benefits will receive a monthly payment equal to the amount determined under (ii) above. Such payments shall commence effective with the first day of the month following the month of the participant's death. If such surviving spouse receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s). Monthly payments hereunder shall permanently cease upon the death of the surviving spouse, effective with the monthly payment for the month following the month of the surviving spouse's death. Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. (v) Amount, timing, and source of lump sum survivor benefit payout. A -------------------------------------------------------------- surviving spouse entitled to lump sum supplemental survivor benefit will receive a lump sum payment. This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity. Such lump sum payment shall be made within 60 days after the participant's death. The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets. A surviving spouse who receives a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments. (vi) Death of surviving spouse entitled to lump sum payout. In the ----------------------------------------------------- event of the death of a surviving spouse before the spouse receives the lump sum payment under section 6(a)(v) no payment shall be made. 7. Death Benefit. Constellation Energy Group shall make arrangements, through ------------- its split-dollar life insurance program or otherwise, for life insurance coverage for each designated participant providing that the participant's beneficiary shall receive, as a pre-retirement (or pre-rollout benefit for participants as of 4/1/2000) death benefit, an amount which is approximately equal to three times the participant's base salary control point plus target annual incentive (as determined in the sole discretion of the Plan Administrator), and as a post-retirement death benefit(or post- rollout benefit for participants as of 4/1/2000), an amount which is approximately equal to two times the participant's base salary control point plus target annual incentive (as determined in the sole discretion of the Plan Administrator), as set forth in a separate agreement between the participant and his/her employer. As determined in the sole discretion of the Plan Administrator, in the event that either (i) a participant is ineligible to receive the type of life insurance coverage provided to other participants under this Plan, or (ii) such coverage is not available on reasonably cost-effective terms as a result of any penalty for smoking or other factors that are reflected in the insurance carrier's rates, then Constellation Energy Group shall provide a benefit that, in the discretion of the Plan Administrator, is substantially equivalent to the cost of the benefit provided to other participants under this Plan. 8. Dependent Death Benefit. For a participant with a split-dollar policy ----------------------- under Section 7, in the event of the death of a participant's qualified dependent while the participant is an active employee of Constellation Energy Group or a subsidiary of Constellation Energy Group, Constellation Energy Group shall make a death benefit payment to the participant, from general corporate assets. For purposes of this Section 8, qualified dependent shall have the same meaning as set forth in Constellation Energy Group's Family Life Insurance Plan. For purposes of this Section 8, the amount of death benefit payment shall be the highest amount of insurance that would have been payable with respect to such qualified dependent if coverage had been provided under Constellation Energy Group's Family Life Insurance Plan. The dependent death benefit payment under this Plan shall be grossed-up for income tax withholding. 9. Miscellaneous. None of the benefits provided under this Plan shall be ------------- subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability; and (iii) any policy of insurance written by a commercial carrier on a split-dollar basis shall be assignable. This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall reduce any previously accrued supplemental pension benefit under this Plan or impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action. All amendments to this Plan which would increase or decrease the compensation of any Officer of Constellation Energy Group, either directly or indirectly, must be approved by the Board of Directors. All other permissible amendments may be made at the written direction of the Committee. Notwithstanding anything else in this Plan to the contrary, the Constellation Energy Group Board of Directors may authorize a Participant to be eligible for benefits or may increase benefit payments. Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person. The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974. Constellation Energy Group shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust. Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of Constellation Energy Group and no person other than Constellation Energy Group shall by virtue of the provisions of this Plan have any interest in such funds and assets. To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group. In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the "New Company"), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan. This Plan shall be governed in all respects by Maryland law. EX-12.A 6 0006.txt COMPUTATION RATIO OF EARNINGS TO FIXED CHARGES EXHIBIT 12(a) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended -------------------------------------------- December December December December December 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss)...... $ 345.3 $ 326.4 $ 305.9 $254.1 $ 272.3 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends........................ 221.4 182.5 169.3 145.1 148.3 ------- ------- ------- ------- ------- Adjusted Income................... $ 566.7 $ 508.9 $ 475.2 $ 399.2 $ 420.6 ------- ------- ------- ------- ------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness............. $ 261.5 $ 245.7 $ 255.3 $ 234.2 $ 203.9 Earnings required for BGE Preference Stock Dividends...... 21.9 21.0 33.8 45.1 59.4 Capitalized Interest............. 21.1 2.7 3.6 8.4 15.7 Interest Factor in Rentals....... 2.2 1.8 1.9 1.9 1.5 ------- ------- ------- ------- ------- Total Fixed Charges.............. $ 306.7 $ 271.2 $ 294.6 $ 289.6 $ 280.5 ------- ------- ------- ------- ------- Earnings(1)....................... $ 852.3 $ 777.4 $ 766.2 $ 680.4 $ 685.4 ======= ======= ======= ======= ======= Ratio of Earnings to Fixed Charges.......................... 2.78 2.87 2.60 2.35 2.44
(1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of unconsolidated subsidiaries, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest. 94 EX-12.B 7 0007.txt COMPUTATION RATIO TO FIXED CHARGES AND COMBINED FIX EXHIBIT 12(b) BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended -------------------------------------------- December December December December December 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss)...... $ 143.5 $ 328.4 $ 327.7 $ 282.8 $ 310.8 Taxes on Income................... 94.2 182.0 181.3 161.5 169.2 ------- ------- ------- ------- ------- Adjusted Income................... $ 237.7 $ 510.4 $ 509.0 $ 444.3 $ 480.0 ------- ------- ------- ------- ------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness............. $ 186.8 $ 206.4 $ 255.3 $ 234.2 $ 203.9 Capitalized Interest............. -- 0.4 3.6 8.4 15.7 Interest Factor in Rentals....... 0.9 1.0 1.9 1.9 1.5 ------- ------- ------- ------- ------- Total Fixed Charges.............. $ 187.7 $ 207.8 $ 260.8 $ 244.5 $ 221.5 ------- ------- ------- ------- ------- Preferred and Preference Dividend Requirements:(1) Preferred and Preference Dividends....................... $ 13.2 $ 13.5 $ 21.8 $ 28.7 $ 38.5 Income Tax Required.............. 8.7 7.5 12.0 16.4 20.9 ------- ------- ------- ------- ------- Total Preferred and Preference Dividend Requirements........... $ 21.9 $ 21.0 $ 33.8 $ 45.1 $ 59.4 ------- ------- ------- ------- ------- Total Fixed Charges and Preferred and Preference Dividend Requirements..................... $ 209.6 $ 228.8 $ 294.6 $ 289.6 $ 280.5 ======= ======= ======= ======= ======= Earnings(2)....................... $ 425.4 $ 717.8 $ 766.2 $ 680.4 $ 685.4 ======= ======= ======= ======= ======= Ratio of Earnings to Fixed Charges.......................... 2.27 3.45 2.94 2.78 3.10 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements..................... 2.03 3.14 2.60 2.35 2.44
(1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. 95 EX-21 8 0008.txt SUBSIDIARIES OF CONSTELLATION ENERGY GROUP, INC. EXHIBIT 21 SUBSIDIARIES OF CONSTELLATION ENERGY GROUP, INC.*
Jurisdiction of Incorporation ------------- Baltimore Gas and Electric Company................................ Maryland Constellation Holdings, Inc....................................... Maryland Constellation Investments, Inc.................................... Maryland Constellation Power, Inc.......................................... Maryland Constellation Real Estate Group, Inc.............................. Maryland Constellation Enterprises, Inc.................................... Maryland Constellation Power Source, Inc................................... Delaware Constellation Energy Source, Inc.................................. Delaware BGE Home Products & Services, Inc................................. Maryland Constellation Nuclear, LLC........................................ Maryland Calvert Cliffs Nuclear Power Plant, Inc........................... Maryland Constellation Nuclear Services, Inc............................... Maryland Constellation Power Source Generation, Inc........................ Maryland Constellation Power Source Holdings, Inc.......................... Maryland BGE Capital Trust I............................................... Delaware
* The names of certain indirectly owned subsidiaries have been omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary pursuant to Rule 1-02(w) of Regulation S-X. 96 EX-23 9 0009.txt CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 and Form S-8 (File Nos. 333-36380, 333-59601, 33-57658, 333-56572, 333-24705, and 33-49801 and 33-59545, 333-45051, 333-46980, and 33- 56084, respectively) of Constellation Energy Group, Inc. of our report dated January 17, 2001 relating to the financial statements and financial statement schedule, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP __________________________ PRICEWATERHOUSECOOPERS LLP Baltimore, Maryland March 30, 2001 97 -----END PRIVACY-ENHANCED MESSAGE-----